As filed with the Securities and Exchange Commission on February 11, 2014
Registration No. 333-193337
|
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 1
to
Form S-4
REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933
_______________________________
SARATOGA RESOURCES, INC.
(exact name of registrant as specified in its charter)
_______________________________
Texas |
| 1311 |
| 76-0314489 |
(State or Other Jurisdiction of Incorporation or Organization) |
| (Primary Standard Industrial Classification Code Number) |
| (I.R.S. Employer Identification No.) |
3 Riverway, Suite 1810 |
| Thomas Cooke |
(Address, Including Zip Code, and Telephone Number, |
| (Name, Address, Including Zip Code, and |
_______________________________
Copies to:
David K. Bowsher Adams and Reese LLP 1901 Sixth Avenue North, Suite 3000 Birmingham, Alabama 35203 (205) 250-5000 |
| Michael W. Sanders Michael W. Sanders, Attorney at Law 13603 Crosslyn Ln Cypress, Texas 77429 (281) 758-4136 |
Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.
If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. o
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration number of the earlier effective registration statement for the same offering. o
If this Form is a post effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o Accelerated filer o Non-accelerated filer o Smaller reporting company ý
If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction.
Exchange Act Rule 13e-4(i) (Cross-Border Issuer Tender Offer) |
| o |
Exchange Act Rule 13d-1(d) (Cross-Border Third-Party Issuer Tender Offer) |
| o |
CALCULATION OF REGISTRATION FEE
Title of Each Class of Securities to be Registered(1) |
| Amount to be Registered |
| Proposed Maximum Offering Price per Note(1) |
| Proposed Maximum Aggregate Offering Price(1) |
| Amount of Registration Fee(3) | |||
10.0% Senior Secured Notes due 2015 |
| $ | 54,600,000 |
| 100% |
| $ | 54,600,000 |
| $ | 7,032.48 |
Guarantees(2) |
|
| N/A |
| N/A |
|
| N/A |
|
| — |
Total |
| $ | 54,600,000 |
|
|
| $ | 54,600,000 |
| $ | 7,032.48 |
(1)
Estimated solely for the purpose of calculating the registration fee in accordance with Rule 457(f) under the Securities Act of 1933.
(2)
No separate consideration will be received for the guarantees, and no separate fee is payable pursuant to Rule 457(a) under the Securities Act of 1933.
(3)
In accordance with Rule 457(n) under the Securities Act of 1933, no separate fee is payable with respect to guarantees of the securities being registered.
(4)
Previously paid
Each Registrant hereby amends this Registration Statement on such dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.
TABLE OF ADDITIONAL REGISTRANT GUARANTORS
Exact Name of Registrant Guarantors (1) |
| State or Other Jurisdiction of Incorporation or Formation |
| Primary Standard Industrial Classification Code Number |
| IRS Employer Identification Number | |||
Harvest Oil & Gas, LLC |
|
| Louisiana |
|
| 1311 |
|
| 20-1430003 |
The Harvest Group LLC |
|
| Louisiana |
|
| 1311 |
|
| 20-1233158 |
Lobo Resources, Inc. |
|
| Texas |
|
| 1311 |
|
| 74-2697201 |
Lobo Operating, Inc. |
|
| Texas |
|
| 1311 |
|
| 76-0436990 |
(1)
The address for each of the Guarantors is 3 Riverway, Suite 1810, Houston, Texas 77056 and the telephone number for the Registrant Guarantors (713) 458-1560.
The information in this preliminary prospectus is not complete and may be changed without notice. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.
Subject to Completion, dated February 11, 2014
PROSPECTUS
![[saras4a021114002.gif]](saras4a021114002.gif)
Saratoga Resources, Inc.
Offer to Exchange
$54,600,000 of 10.0% Senior Secured Notes due 2015
that have been registered under the Securities Act of 1933
for
$54,600,000 of 10.0% Senior Secured Notes due 2015
that have not been registered under the Securities Act of 1933
Saratoga Resources, Inc. is offering to exchange registered 10.0% Senior Secured Notes due 2015, or the “exchange notes,” for any and all of its unregistered 10.0% Senior Secured Notes due 2015, or the “outstanding notes,” that were issued pursuant to a private placement on November 22, 2013. We refer to the outstanding notes and the exchange notes together in this prospectus as the “notes.” We refer to this exchange as the “exchange offer.” The exchange notes are substantially identical to the outstanding notes, except the exchange notes are registered under the Securities Act of 1933, as amended (the “Securities Act”), and the transfer restrictions and registration rights, and related additional interest provisions, applicable to the outstanding notes will not apply to the exchange notes. The exchange notes will represent the same debt as the outstanding notes and we will issue the exchange notes under the same indenture used in issuing the outstanding notes.
Terms of the exchange offer:
•
The exchange offer expires at 5:00 p.m., New York City time, on , 2014, unless we extend it.
•
The exchange offer is subject to customary conditions, which we may waive.
•
We will exchange all outstanding notes that are validly tendered and not withdrawn prior to the expiration of the exchange offer for an equal principal amount of exchange notes. All interest due and payable on the outstanding notes will become due and payable on the same terms under the exchange notes.
•
You may withdraw your tender of outstanding notes at any time prior to the expiration of the exchange offer.
•
If you fail to tender your outstanding notes, you will continue to hold unregistered, restricted securities, and your ability to transfer them could be adversely affected.
•
We believe that the exchange of exchange notes for outstanding notes will not be a taxable transaction for U.S. federal income tax purposes, but you should see the discussion under the caption “Material U.S. Federal Income and Estate Tax Considerations” for more information.
•
We will not receive any proceeds from the exchange offer.
Please read “Risk Factors” beginning on page 7 for a discussion of factors you should consider before deciding whether to participate in the exchange offer.
Each broker-dealer that receives the exchange notes for its own account pursuant to this exchange offer must acknowledge by way of the letter of transmittal that it will deliver a prospectus in connection with any resale of the exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, such broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of the exchange notes received in exchange for outstanding notes where such outstanding notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. Until , 2014 all dealers that effect transactions in the exchange notes, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters with respect to their unsold allotments or subscriptions. We have agreed that, until , 2014, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”
Neither the Securities and Exchange Commission (the “SEC”) nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
YOU SHOULD READ THIS ENTIRE DOCUMENT AND THE ACCOMPANYING LETTER OF TRANSMITTAL AND RELATED DOCUMENTS AND ANY AMENDMENTS OR SUPPLEMENTS CAREFULLY BEFORE MAKING YOUR DECISION TO PARTICIPATE IN THE EXCHANGE OFFER.
The date of this prospectus is , 2014.
TABLE OF CONTENTS
| Page |
ii | |
1 | |
7 | |
30 | |
38 | |
Management’s Discussion and Analysis of Financial Condition and Results of Operations | 39 |
60 | |
76 | |
78 | |
80 | |
Security Ownership of Certain Beneficial Owners and Management | 83 |
84 | |
137 | |
140 | |
142 | |
142 | |
143 | |
144 |
_______________________________________________________
This prospectus is part of a registration statement we filed with the SEC. In making your decision whether to participate in this exchange offer, you should rely only on the information contained in or incorporated by reference into this prospectus and in the letter of transmittal accompanying this prospectus. We have not authorized any other person to provide you with additional or different information. If you receive any unauthorized information, you must not rely on it. We are not making an offer to sell these securities in any jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus or in the documents incorporated by reference into this prospectus is accurate as of any date other than the date on the front cover of this prospectus or the date of such incorporated documents, as the case may be.
This prospectus incorporates by reference business and financial information about us that is not included in or delivered with this prospectus. This information is available without charge upon written or oral request directed to: Saratoga Resources, Inc., Attention: Investor Relations, 3 Riverway, Suite 1810, Houston, Texas 77056; telephone number: (713) 458-1560.
_______________________________________________________
i
GLOSSARY OF OIL AND NATURAL GAS TERMS
We have included below the definitions for certain oil and natural gas terms used in this prospectus:
“3-D seismic” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two dimensional, seismic.
“anticline” An arch-shaped fold in rock in which rock layers are upwardly convex. The oldest rock layers form the core of the fold, and outward from the core progressively younger rocks occur.
“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in this offering circular in reference to oil and other liquid hydrocarbons.
“Bcf” One billion cubic feet of natural gas.
“behind pipe” Reserves which are expected to be recovered from zones behind casing in existing wells, which require additional completion work or a future recompletion prior to the start of production.
“Boe” Barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
“Boepd” Boe per day.
“Bopd” Bbls of oil or other liquid hydrocarbon per day.
“Btu” One British thermal unit.
“completion” The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“development well” A well drilled within the proved area of an oil and gas reservoir to the depth of a stratigraphic horizon known to be productive.
“dry hole” An exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
“exploratory well” A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.
“farm-in” An agreement between a participant who brings a property into the venture and another participant who agrees to spend an agreed amount to explore and develop the property and has no right of reimbursement but may gain a vested interest in the venture. A “farm-in” describes the position of the participant who agrees to spend the agreed-upon sum of money to gain a vested interest in the venture.
“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“gross wells” Total number of producing wells in which we have an interest.
“held by production” or “HBP” A provision in an oil and gas lease that perpetuates a company’s right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or gas.
“lease operating expenses” The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.
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“LLS” Louisiana Light Sweet crude oil, being a high quality low-sulfur content premium crude oil.
“MBbl” One thousand barrels of oil or other liquid hydrocarbons.
“MBoe” Thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
“MBoepd” Thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids per day.
“Mcf” One thousand cubic feet of natural gas.
“Mcfpd” Mcf per day.
“MMBbl” One million barrels of oil or other liquid hydrocarbons.
“MMBoe” Million barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
“MMBtu” One million British Thermal Units.
“MMcf” One million cubic feet of natural gas.
“net acre” Fractional ownership working interest multiplied by gross acres. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
“net revenue interest” A share of production after all burdens, such as royalty and overriding royalty, have been deducted from the working interest. It is the percentage of production that each party actually receives.
“net wells” The sum of our fractional interests owned in gross wells.
“NYMEX” The New York Mercantile Exchange.
“PDP” Proved developed producing.
“PDNP” Proved developed nonproducing.
“plugback” To shut off lower formation in a well bore.
“plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.
“possible reserves” Those that may be present but are not probable.
“probable reserves” Those that have a 50% chance of being present but are not proved.
“proved developed reserves” Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
“proved reserves” Estimated quantities that geologic engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
“proved undeveloped reserves” Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.
“productive wells” Producing wells and wells capable of production.
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“producing well” A well found to be capable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.
“PUD” Proved undeveloped.
“PV-10” The discounted present value of the estimated future gross revenue to be generated from the production of proved oil and gas reserves (using pricing assumptions consistent with, and after deducting estimated abandonment costs to the extent required by, SEC guidelines), net of estimated future development and production costs, before income taxes and without giving effect to non-property related expense, discounted using an annual discount rate of 10% and calculated in a manner consistent with SEC guidelines.
“recompletion” After the initial completion of a well, the action and techniques of reentering the well and redoing or repairing the original completion to restore the well’s productivity.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“shut-in” To close valves on a well so that it stops producing; said of a well on which the valves are closed.
“stratigraphic trap” A variety of sealed geologic container capable of retaining hydrocarbons, formed by changes in rock type or pinch-outs, unconformities, or sedimentary features such as reefs.
“through-tubing” Pertaining to a range of products, services and techniques designed to be run through, or conducted within, the production tubing of an oil or gas well. The term implies an ability to operate within restricted-diameter tubulars and is often associated with live-well intervention since the tubing is in place.
“trap” A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.
“working interest” The interest in an oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.
“workover” The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.
“WTI” West Texas Intermediate crude oil, being light, sweet crude oil with high API gravity and low sulfur content used as a benchmark for U.S. crude oil refining and trading.
iv
SUMMARY
This summary highlights selected information about us, but does not contain all the information that may be important to you. This prospectus includes specific information about the exchange offer and our business. You should read this prospectus carefully, including the matters set forth under the caption “Risk Factors” before making a decision whether to participate in the exchange offer.
In this prospectus, except under the caption “Description of the Exchange Notes” and unless the context indicates otherwise, references to “Saratoga,” the “Company,” “we”, “our” and “us” refer to Saratoga Resources, Inc. and its subsidiaries.
Our Company
We are an independent oil and natural gas company engaged in the acquisition, development, exploitation, exploration and production of crude oil and natural gas properties. Our lease holdings totaled 51,890 acres at September 30, 2013, comprised of our principal producing properties covering 32,076 acres in the transitional coastline and protected in-bay environment on parish and state leases of south Louisiana and an additional 19,814 acres of leases in the shallow Gulf of Mexico shelf.
At September 30, 2013, we operated or had interests in 94 producing wells and our principal properties covered approximately 51,890 gross/net acres, 31,031 acres, or 60% of the total, of which were held by production without near-term lease expirations, across 10 fields in the transitional coastline and protected in-bay environment on parish and state leases in south Louisiana as well as in the shallow Gulf of Mexico shelf. We own approximately 100% working interest in all our properties, with the only exception being a single well where we have an overriding royalty interest. Our net revenue interests in our properties range from 69% to 82%, with our average net revenue interest on a net acreage leasehold basis being approximately 75%. We operate over 99% of the wells that comprise our PV-10, enabling us to effectively exercise management control of our operating costs, capital expenditures and the timing and method of development of our properties.
Corporate Information
Our principal executive offices are located at 3 Riverway, Suite 1810, Houston, Texas 77056. We can be reached at (713) 458-1560, and our website address is www.saratogaresources.com. Information on our website is not part of this prospectus.
1
The Exchange Offer
On November 22, 2013, we completed a private offering of $54.6 million aggregate principal amount of the outstanding notes for cash in the amount of $27.3 million and surrender for cancellation of $27.3 million in face amount of 12½% senior secured notes due 2016. As part of this private offering, we entered into a registration rights agreement with the purchasers of the outstanding notes in which we agreed, among other things, to use our commercially reasonable efforts to complete the exchange offer no later than approximately 165 days after November 22, 2013. The following is a summary of the exchange offer.
Outstanding Notes | On November 22, 2013, we issued $54.6 million aggregate principal amount of 10.0% Senior Secured Notes due 2015. The outstanding notes were issued for a combination of cash in the amount of $27.3 million and surrender for cancellation of $27.3 million in face amount of 12½% senior secured notes due 2016. |
Exchange Notes | 10.0% Senior Secured Notes due 2015. The terms of the exchange notes are identical to the terms of the outstanding notes, except that the transfer restrictions, registration rights and provisions for additional interest relating to the outstanding notes will not apply to the exchange notes. |
Exchange Offer | We are offering to exchange up to $54.6 million principal amount of our 10.0% Senior Secured Notes due 2015 that have been registered under the Securities Act of 1933, or the Securities Act, for an equal amount of our outstanding 10.0% Senior Secured Notes due 2015 issued on November 22, 2013 to satisfy our obligations under the registration rights agreement that we entered into when we issued the outstanding notes in a transaction exempt from registration under the Securities Act. |
Expiration Date | The exchange offer will expire at 5:00 p.m., New York City time, on , 2014, unless we extend it. |
Conditions to the Exchange Offer | The registration rights agreement does not require us to accept outstanding notes for exchange if the exchange offer or the making of any exchange by a holder of the outstanding notes would violate any applicable law or SEC policy. There is no condition to the exchange offer that a minimum aggregate principal amount of outstanding notes be tendered. Please read “The Exchange Offer — Conditions to the Exchange Offer” for more information about the conditions to the exchange offer. |
Procedures for Tendering Outstanding Notes | To participate in this exchange offer, you must complete, sign and date the letter of transmittal or its facsimile and transmit it, together with your outstanding notes to be exchanged and all other documents required by the letter of transmittal, to The Bank of New York Mellon Trust Company, N.A., as exchange agent, at its address indicated herein. In the alternative, you can tender your original notes by book-entry delivery following the procedures described in this prospectus. |
| For more details, please read “The Exchange Offer — Terms of the Exchange Offer” and “The Exchange Offer — Procedures for Tendering.” |
Guaranteed Delivery Procedures | None. |
Withdrawal of Tenders | You may withdraw your tender of outstanding notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent before 5:00 p.m., New York City time, on the expiration date of the exchange offer. Please read “The Exchange Offer — Withdrawal of Tenders.” |
2
Acceptance of Outstanding Notes and Delivery of Exchange Notes | If you fulfill all conditions required for proper acceptance of outstanding notes, we will accept any and all outstanding notes that you properly tender in the exchange offer before 5:00 p.m., New York City time, on the expiration date. We will return to you any outstanding note that we do not accept for exchange without expense promptly after the expiration date. We will deliver the exchange notes promptly after the expiration date. Please read “The Exchange Offer — Terms of the Exchange Offer.” |
Use of Proceeds | We will not receive any proceeds from the issuance of the exchange notes. We are making the exchange offer solely to satisfy our obligations under the registration rights agreement. |
Consequences of Failure to Exchange Outstanding Notes | If you do not exchange your outstanding notes in the exchange offer, you will no longer be able to require us to register the outstanding notes under the Securities Act, except in the limited circumstances provided under our registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the outstanding notes unless we have registered the outstanding notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act. |
Material U.S. Federal Income Tax Considerations | We believe that the exchange of exchange notes for outstanding notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read “Material U.S. Federal Income and Estate Tax Considerations.” |
Exchange Agent | We have appointed The Bank of New York Mellon Trust Company, N.A. as the exchange agent for the exchange offer. You should direct questions and requests for assistance and requests for additional copies of this prospectus (including the letter of transmittal) to the exchange agent addressed as follows: |
| The Bank of New York Mellon Trust Company, N.A. as Exchange Agent |
| c/o The Bank of New York Mellon Corporation |
| Corporate Trust Operations – Reorganization Unit |
| 111 Sanders Creek Parkway |
| East Syracuse, NY 13057 |
| Attention: Dacia Brown-Jones |
| Telephone: (315) 414-3349 |
| Facsimile: (732) 667-9408 |
3
Terms of the Exchange Notes
The exchange notes will be identical to the outstanding notes, except that the exchange notes will be registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest. The exchange notes will evidence the same debt as the outstanding notes, and the same indenture will govern the exchange notes and the outstanding notes. We refer to both the exchange notes, the outstanding notes, and the original issuance notes together as the “notes.”
The following summary contains basic information about the exchange notes and is not intended to be complete. It does not contain all the information that may be important to you. For a more complete understanding of the exchange notes, please read “Description of the Exchange Notes.”
Issuer | Saratoga Resources, Inc. |
Notes Offered | $54,600,000 aggregate principal amount of 10.0% senior secured notes due 2015. |
Maturity Date | December 31, 2015. |
Interest Rate | The exchange notes will bear interest at a rate of 10.0% per year. |
Interest Payment Dates | March 31, June 30, September 30 and December 31 of each year to holders of record as of the preceding March 15, June 15, September 15 and December 15, respectively. The initial interest payment on the exchange notes will include all accrued and unpaid interest on the outstanding notes exchanged therefor. See “Description of the Exchange Notes — Principal, Maturity and Interest.” |
Guarantees | The exchange notes will be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of our existing and future domestic subsidiaries, which we refer to in this prospectus as the “guarantors.” |
Security Interest | The notes and the guarantees will be secured by liens on substantially all of our and the guarantors’ assets, subject to certain exceptions and permitted liens. Pursuant to the terms of an intercreditor agreement, discussed below, the notes rank senior in right, priority, operation, effect and all other respects to any liens with respect to collateral securing the obligations under the indenture (the “Second Lien Indenture”) relating to $125.2 million in face amount of 12½% senior secured notes due 2016 (the “Second Lien Notes”). Under the terms of the indenture governing the notes (the “First Lien Indenture”), additional notes issued under the First Lien Indenture and secured by collateral on a pari passu or senior basis with the lien on the collateral securing the notes may not exceed $10.0 million without the prior consent of holders of at least 75% in aggregate principal amount of the notes outstanding. See “Description of the Exchange Notes—Security.” |
Intercreditor Agreement | Pursuant to the terms of an intercreditor agreement entered into with The Bank of New York Mellon Trust Company, N.A., in its capacity as trustee and collateral agent under the First Lien Indenture (the “First Lien Agent”), and The Bank of New York Mellon Trust Company, N.A., in its capacity as trustee and collateral agent (the “Second Lien Agent”) under the Second Lien Indenture, the holders of the notes and any other pari passu indebtedness will receive proceeds from the collateral prior to the holders of Second Lien Notes. In addition to defining the relative priorities of the respective security interests in the assets securing the notes, the intercreditor agreement sets forth certain matters relating to administration of security interests, exercise of remedies, certain bankruptcy-related provisions and other intercreditor matters. See “Description of the Exchange Notes—Intercreditor Agreement.” |
4
Ranking | The exchange notes will be our and the guarantors’ senior secured obligations. The exchange notes will: |
| • |
| rank equal in right of payment with all of our and the guarantors’ existing and future senior indebtedness; |
| • |
| rank senior in right of payment to all of our and the guarantors’ existing and future subordinated indebtedness; |
| • |
| be effectively senior to all of our and the guarantors’ existing and future unsecured indebtedness to the extent of the value of the collateral securing such indebtedness; |
| • |
| be effectively senior to our and the guarantors’ obligations under the Second Lien Indenture; and |
| • |
| be structurally junior to all existing and future indebtedness and other liabilities of each of our non-guarantor subsidiaries, if any. |
Redemption of the Notes at Our Option | We may redeem some or all of the notes, at our sole option and at any time, at 100% of the principal amount to be redeemed plus accrued and unpaid interest, if any, to the date of redemption. See “Description of the Exchange Notes—Optional Redemption.” |
Change of Control | If we experience certain kinds of changes of control (as defined in the indenture governing the notes), the holders of the notes will have the right to require us to purchase all or a portion of their notes at an offer price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase. See “Description of the Exchange Notes — Repurchase at the Option of Holders — Change of Control.” |
Asset Sale | Upon certain asset sales, we may be required to offer to use the net proceeds of an asset sale to purchase the notes at 100% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase. See “Description of the Exchange Notes — Repurchase at the Option of Holders — Asset Sale.” |
Certain Covenants | The indenture governing the exchange notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: |
| • |
| transfer or sell assets or use asset sale proceeds; |
| • |
| pay dividends or make distributions, redeem subordinated debt or make other restricted payments; |
| • |
| make certain investments; |
| • |
| incur or guarantee additional debt or issue preferred equity securities; |
| • |
| issue or sell capital stock of certain subsidiaries; |
| • |
| create or incur certain liens on our assets; |
| • |
| incur dividend or other payment restrictions affecting our restricted subsidiaries; |
| • |
| merge, consolidate or transfer all or substantially all of our assets; |
5
| • |
| enter into certain transactions with affiliates; |
| • |
| engage in a business other than a business that is the same or similar to our current business and reasonably related businesses; and |
| • |
| take or omit to take any actions that would adversely affect or impair in any material respect the collateral securing the notes. |
| These covenants are subject to a number of important exceptions and limitations and are described in more detail under “Description of the Exchange Notes — Certain Covenants.” |
Absence of a Public Market for the Notes | The exchange notes generally will be freely transferable, but will also be new securities for which there is currently no established market. We do not intend to make a trading market in the exchange notes after the exchange offer. Accordingly, a market for the exchange notes may not develop, or if one does develop, it may not provide adequate liquidity. |
Global Notes | The exchange notes will be evidenced by one or more global notes deposited with the trustee as custodian for DTC. These global notes will be registered in the name of Cede & Co., as DTC’s nominee. |
Risk Factors | You should consider carefully all of the information set forth in this prospectus and incorporated by reference and, in particular, you should evaluate the risks described under “Risk Factors” in this prospectus and in our filings with the SEC before making a decision whether to participate in the exchange offer. |
No Listing of the Notes | We do not intend to apply to list the notes on any securities exchange. |
Trustee and Exchange Agent | The Bank of New York Mellon Trust Company, N.A. |
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RISK FACTORS
You should consider carefully the risks discussed below before making a decision whether to participate in the exchange offer. Additional risks and uncertainties described elsewhere in this prospectus may also adversely affect our business, operating results, financial condition and prospects, as well as the value of the exchange notes.
If any of the following risks actually were to occur, our business, financial condition, results of operations or cash flow could be affected materially and adversely. In that case, you could lose all or part of your investment in or fail to achieve the expected return on the notes.
Risks Related to the Exchange Offer
If you fail to exchange outstanding notes, existing transfer restrictions will remain in effect and the market value of outstanding notes may be adversely affected because they may be more difficult to sell.
If you fail to exchange outstanding notes for exchange notes under the exchange offer, you will continue to be subject to the existing transfer restrictions on your outstanding notes. In general, the outstanding notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except in connection with this exchange offer or as required by the registration rights agreement, we do not intend to register resales of the outstanding notes.
Any tenders of outstanding notes under the exchange offer will reduce the principal amount of the currently outstanding notes. Due to the corresponding reduction in liquidity, this may have an adverse effect upon, and increase the volatility of, the market price of any currently outstanding notes that you continue to hold following completion of the exchange offer.
Risks Related to the Notes
Forward-looking production estimates presented in this prospectus will differ from our actual results.
Forward-looking production estimates we have included, or that may be incorporated by reference, in this prospectus are based upon a number of assumptions and on information that we believe are reliable as of today. However, these forward-looking production estimates and assumptions are inherently subject to significant business and economic uncertainties, many of which are beyond our control. These forward-looking production estimates are necessarily speculative in nature, and you should expect that some or all of the assumptions will not materialize. Actual results will vary from the forward-looking production estimates and the variations will likely be material and are likely to increase over time. Consequently, the inclusion of these forward-looking production estimates in this prospectus should not be regarded as a representation by us or any other person that the forward-looking production estimates will actually be achieved. Moreover, we do not intend to update or otherwise revise these forward-looking production estimates to reflect events or circumstances after the date of this prospectus to reflect the occurrence of unanticipated events. You are cautioned not to place undue reliance on the forward-looking production estimates.
Our forward-looking production estimates were not prepared with a view toward compliance with published guidelines of the SEC, the American Institute of Certified Public Accountants, the Society of Petroleum Engineers, the World Petroleum Congress or any other regulatory or professional body or generally accepted accounting principles. No independent accountants or independent petroleum engineers compiled or examined the forward-looking production estimates, and accordingly no independent accountant or independent petroleum engineer has expressed an opinion or any other form of assurances with respect thereto or has assumed any responsibility for the forward-looking production estimates. Further, our independent petroleum engineers made different assumptions when calculating our respective proved reserve estimates. As a result, our forward-looking production estimates may not accurately portray our proved reserves in the future.
Our leverage and debt service obligations may adversely affect our cash flow and our ability to make payments on the notes.
We have a substantial amount of debt currently outstanding. As of September 30, 2013, on an as adjusted basis after giving effect to the issuance of the outstanding notes and related transactions that occurred at or about the time of the issuance of the outstanding notes, we would have had approximately $179.8 million of debt outstanding.
Our substantial level of indebtedness could have important consequences to you, including the following:
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it may make it difficult for us to satisfy our obligations under the notes, our other indebtedness and contractual and commercial commitments;
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we must use a substantial portion of our cash flow from operations to pay interest on the notes and our other indebtedness, which will reduce the funds available to us for other purposes;
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our ability to obtain additional debt financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes may be limited;
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our flexibility in reacting to changes in the industry may be limited and we could be more vulnerable to adverse changes in our business or economic conditions in general; and
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we may be at a competitive disadvantage to those of our competitors who operate on a less leveraged basis.
Despite current indebtedness levels, we may still be able to incur more debt, which would increase the risks associated with our substantial leverage.
Even with our existing debt levels, we and our subsidiaries may be able to incur additional indebtedness in the future. Although the indenture governing the notes includes restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions and, under certain circumstances, the amount of indebtedness that could be incurred in compliance with these restrictions could be substantial. If we incur additional indebtedness, the related risks that we now face would intensify and could further exacerbate the risks associated with our substantial leverage.
We may not be able to generate sufficient cash flow to meet our debt service and other obligations, including the notes, due to events beyond our control.
Our ability to generate cash flows from operations and to make scheduled payments on or refinance our indebtedness, including the notes, and to fund working capital needs and planned capital expenditures will depend on our future financial performance and our ability to generate cash in the future. Our future financial performance will be affected by a range of economic, financial, competitive, business and other factors that we cannot control, such as general economic and financial conditions in the oil and gas industry, the economy generally or other risks summarized here. A significant reduction in operating cash flows resulting from adverse changes in the oil and gas industry or general economic conditions, increased competition or other events beyond our control could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations, prospects and our ability to service our debt and other obligations, including the notes. If we are unable to service our indebtedness or to fund our other liquidity needs, we may be forced to adopt an alternative strategy that may include actions such as reducing or delaying capital expenditures, selling assets, restructuring or refinancing our indebtedness, seeking additional capital, or any combination of the foregoing. If we raise additional debt, it would increase our interest expense, leverage and our operating and financial costs. We cannot assure you that any of these alternative strategies could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on the notes and any other indebtedness or to fund our other liquidity needs. Reducing or delaying capital expenditures or selling assets could delay or reduce future cash flows. In addition, the terms of existing or future debt agreements, including the indenture governing the notes, may restrict us from adopting any of these alternatives. We cannot assure you that our business will generate sufficient cash flows from operations or that future borrowings will be available in an amount sufficient to enable us to pay our indebtedness, including these notes, or to fund our other liquidity needs.
The failure to generate sufficient cash flows or to effect any of these alternatives could significantly adversely affect the value of the notes and our ability to pay amounts due under the notes. If for any reason we are unable to meet our debt service and repayment obligations, including under the notes, we would be in default under the terms of the agreements governing our indebtedness, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable. This would likely in turn trigger cross-acceleration or cross-default rights between our applicable debt agreements. Under these circumstances, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on the notes. In addition, these lenders could then seek to foreclose on our assets that are their collateral. If the amounts outstanding under our indebtedness, including under the notes, were to be accelerated, or were the subject of foreclosure actions, we cannot assure you that our assets would be sufficient to repay in full the money owed to our debt holders, including you as a noteholder.
In particular, we note that we have periodically experienced declines in revenues and profitability associated with curtailment or shut-in of production due to tropical storms and hurricanes and decreases in commodity prices. Declines in revenues and profitability arising from such events may result in reduced cash flows and deferral of planned development activities which may, in turn, result in a delay in the commencement of anticipated revenues from delayed projects. Any such developments in the future could adversely affect our ability to service our debt.
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We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
We are a holding company and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the limited liability company interests and other equity interests in our subsidiaries. As a result, our ability to make required payments on the notes will depend on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, applicable state laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount of the notes, or to repurchase the notes upon the occurrence of a change of control, or if our subsidiaries are unable to satisfy their obligations as guarantors of the notes, we may be required to adopt one or more alternatives, such as a refinancing of the notes. We cannot assure you that we would be able to refinance the notes.
The indenture governing the notes imposes significant operating and financial restrictions which may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.
The indenture governing the notes contains customary restrictions on our activities, including covenants that limit our and our restricted subsidiaries’ ability to:
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| transfer or sell assets or use asset sale proceeds; |
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| incur or guarantee additional indebtedness or issue preferred equity securities; |
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| pay dividends, redeem subordinated indebtedness or make other restricted payments; |
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| make certain investments; |
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| create or incur certain liens on our assets; |
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| incur dividend or other payment restrictions affecting our restricted subsidiaries; |
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| enter into certain transactions with affiliates; |
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| merge, consolidate or transfer all or substantially all of our assets; |
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| engage in a business other than a business that is the same or similar to our current business and reasonably related businesses; and |
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| take or omit to take any actions that would adversely affect or impair in any material respect the collateral securing the notes. |
The restrictions in the indenture governing the notes may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We also may incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. We cannot assure you that we will be granted waivers or amendments to these agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all. The breach of any of these covenants and restrictions could result in a default under the indenture governing the notes. An event of default under any agreement governing our indebtedness could permit some of our lenders to declare all amounts borrowed from them to be due and payable.
Our ability to repurchase the notes with cash upon a change of control or upon an offer to repurchase the notes in the case of an asset sale, as required by the indenture, may be limited.
Upon the occurrence of a change of control, as defined in the indenture governing the notes, we will be required to offer to repurchase all of the outstanding notes at 101% of the aggregate principal amount of the notes repurchased, plus accrued and unpaid interest to the date of repurchase. See “Description of the Exchange Notes—Repurchase at the Option of Holders—Change of Control.” In addition, upon the occurrence of certain asset sales, as defined in the indenture governing the notes, we will be required to offer to repurchase all of the outstanding notes at 100% of the aggregate principal amount of the notes repurchased, plus accrued and unpaid interest to the date of repurchase. See “Description of the Exchange Notes—Repurchase at the Option of Holders—Asset Sales.”
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However, it is possible that we will not have sufficient funds at the time of the change of control or upon an asset sale to make the required repurchase of notes. Our failure to purchase tendered notes would constitute an event of default under the indenture governing the notes, which, in turn, would likely constitute a default under the agreements governing any other indebtedness we may have in place. In that event, we may be required to cure or refinance our other indebtedness, if any, before making an offer to purchase.
Moreover, the agreements governing any future indebtedness we incur may restrict our ability to repurchase the notes, including following a change of control event or upon an asset sale, as required by the indenture. As a result, following such an event, we would not be able to repurchase notes unless we first repay all such indebtedness or obtain a waiver from the holders of such indebtedness to permit us to repurchase the notes. We may be unable to repay all of that indebtedness or obtain a waiver of that type. Any requirement to offer to repurchase outstanding notes may therefore require us to refinance any other outstanding debt, which we may not be able to do on commercially reasonable terms, if at all. These repurchase requirements may also delay or make it more difficult for others to obtain control of us.
In addition, certain important corporate events, such as takeovers, recapitalizations, restructurings, mergers or similar transactions, may not constitute a change of control under the indenture governing the notes and, therefore, would not permit the holders of the notes to require us to repurchase the notes. See “Description of the Exchange Notes—Repurchase at the Option of Holders—Change of Control.”
In addition, the definition of change of control includes a phrase relating to the sale or other transfer of “all or substantially all” of the properties or assets of the company and its subsidiaries, taken as a whole. There is no precise definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty in ascertaining whether a particular transaction would involve a disposition of “all or substantially all” of the assets of the company, and, therefore, it may be unclear as to whether a change of control has occurred and whether the holders of the notes have the right to require us to repurchase such notes.
The notes are secured only to the extent of the value of the assets that have been granted as security for the notes and in the event that the security is enforced against the collateral, the holders of the notes will receive proceeds from the collateral only after certain other permitted indebtedness have been paid in full.
If we default on the notes, the holders of the notes will be secured only to the extent of the value of the assets underlying their security interest. Furthermore, upon enforcement against any collateral or insolvency, proceeds of such enforcement will first be used to pay certain other permitted indebtedness prior to paying the notes. See “—The rights of holders of notes in the collateral may be adversely affected by the intercreditor agreement.”
The value of the noteholders’ security interest in the collateral may not be sufficient to satisfy all our obligations under the notes.
The notes and the guarantees of the notes are secured on a senior secured basis by a lien on the assets that secure our obligations under our existing Second Lien Notes, including accounts, chattel paper, instruments, letter of credit rights, documents, equipment, general intangibles, inventory, cash and deposit accounts, investment property, owned real property and proceeds of the foregoing, in each case, subject to certain permitted liens and certain excluded assets. See “Description of the Exchange Notes—Security.”
If we default on the notes, the holders of the notes will be secured only to the extent of the value of the assets underlying their security interest. Furthermore, upon enforcement against any collateral or insolvency, under the terms of our intercreditor agreement, proceeds of such enforcement will be used first to pay certain other permitted indebtedness and then to pay the notes. To prevent foreclosure, we may be motivated to commence voluntary bankruptcy proceedings, or the holders of the notes and/or various other interested persons may be motivated to institute bankruptcy proceedings against us. The commencement of such bankruptcy proceedings would expose the holders of the notes to additional risks, including additional restrictions on exercising rights against collateral. See “—Rights of holders of notes in the collateral may be adversely affected by bankruptcy proceedings.”
The indenture governing the notes will allow us to incur additional obligations secured by liens in amounts that may be significant. Any additional indebtedness or obligations secured by a lien on the collateral securing the notes could adversely affect the relative position of the holders of the notes with respect to the collateral securing the notes.
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The collateral may be subject to exceptions, defects, encumbrances, liens and other imperfections. Further, the value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral. By its nature, some or all of the collateral may be illiquid and may have no readily ascertainable market value. The value of the assets pledged as collateral for the notes could be impaired in the future as a result of changing trends in the energy markets, economic conditions, our failure to implement our business strategy, competition or other future trends. In the event of a foreclosure, liquidation, bankruptcy or similar proceeding, no assurance can be given that the proceeds from any sale or liquidation of the collateral will be sufficient to pay our obligations under the notes, in full or at all, after first satisfying our obligations under certain other permitted indebtedness. There also can be no assurance that the collateral will be saleable, and, even if saleable, the timing of its liquidation would be uncertain.
In addition, we may not have liens perfected on all of the collateral securing the notes or, in some cases, such liens may not be perfected at all. To the extent certain security interests have not been previously granted, filed and/or perfected, a covenant in the indenture governing the notes requires us to do or cause to be done all things that may be required under applicable law, or that the trustee under the indenture governing the notes from time to time may reasonably request, to grant, preserve, protect and perfect the validity and priority of the security interest in the collateral. We cannot assure you that we will be able to perfect the security interests on a timely basis, and our failure to do so may result in a default under the indenture.
Accordingly, there may not be sufficient collateral to pay all or any of the amounts due on the notes. Any claim for the difference between the amount, if any, realized by holders of the notes from the sale of the collateral securing the notes and the obligations under the notes will rank equally in right of payment with all of our other unsecured unsubordinated indebtedness and other obligations, including trade payables.
With respect to some of the collateral, the trustee’s security interest and ability to foreclose will also be limited by the need to meet certain requirements, such as obtaining third-party consents and making additional filings. If we are unable to obtain these consents or make these filings, the security interests may be invalid and the holders will not be entitled to the collateral or any recovery with respect thereto. We cannot assure you that any such required consents can be obtained on a timely basis or at all. These requirements may limit the number of potential bidders for certain collateral in any foreclosure and may delay any sale, either of which events may have an adverse effect on the sale price of the collateral. Therefore, the practical value of realizing on the collateral may, without the appropriate consents and filings, be limited.
The collateral is subject to casualty risks.
We will be obligated under the indenture and collateral arrangements governing the notes to maintain adequate insurance or otherwise insure against hazards as is typically done by corporations having assets of a similar nature in the same or similar localities. There are, however, certain losses that may be either uninsurable or not economically insurable, in whole or in part. As a result, it is possible that the insurance proceeds will not compensate us fully for our losses. If there is a total or partial loss of any of the pledged collateral, we cannot assure you that any insurance proceeds received by us will be sufficient to satisfy all of our secured obligations, including the notes.
The security interest in after-acquired property may not be perfected promptly or at all.
Applicable law requires that security interests in certain property acquired after the grant of a general security interest can only be perfected at the time such property and rights are acquired and identified. There can be no assurance that the trustee or the collateral agent will monitor, or that we will inform such trustee or collateral agent of, the future acquisition of property and rights that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in such after-acquired collateral. Neither the trustee nor the collateral agent has an obligation to monitor the acquisition of additional property or rights that constitute collateral or the perfection of any security interest. Such failure may result in the loss of the security interest in certain of the after-acquired collateral or the priority of the security interest in favor of the notes against third parties.
There are circumstances other than repayment or discharge of the notes under which the collateral securing the notes and guarantees will be released automatically, without holders’ consent or the consent of the trustee under the indenture governing the notes.
Under various circumstances, all or a portion of the collateral securing the notes and the guarantees may be released automatically, including:
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| a sale, transfer or other disposal of such collateral in a transaction not prohibited under the indenture governing the notes, including the sale of any entity in its entirety that owns or holds such collateral; |
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| to the extent required in accordance with the intercreditor agreement; |
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| to the extent we have defeased or satisfied and discharged the indenture governing the notes; and |
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| with respect to collateral held by a guarantor, upon the release of such guarantor from its guarantee. |
In addition, a guarantee will be automatically released in connection with a sale of such guarantor in a transaction not prohibited under the indenture governing the notes.
Certain assets will be excluded from the collateral.
Certain assets are excluded from the collateral securing the notes, as described in “Description of the Exchange Notes—Security,” including the following:
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| any capital stock of any foreign subsidiaries of the guarantors in excess of 65% of the capital stock of such foreign subsidiaries; |
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| items as to which a security interest cannot be granted without violating contract rights or applicable law; |
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| assets securing purchase money debt or capitalized lease obligations permitted to be incurred under the indenture to the extent the documentation relating to such purchase money debt or capitalized lease obligations prohibits such assets from being collateral; and |
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| certain other exceptions described in the security documents governing the notes. |
If an event of default occurs and the notes are accelerated, the notes will rank equally with the holders of all of our other unsubordinated and unsecured indebtedness and other liabilities with respect to such excluded assets. As a result, if the value of the security interest for the notes and the guarantees is less than the value of the claims of the holders of the notes, no assurance can be provided that the holders of the notes would receive any substantial recovery from the excluded assets.
The rights of holders of notes in the collateral may be adversely affected by the intercreditor agreement.
Under the terms of the intercreditor agreement, the liens securing the obligations under certain permitted indebtedness will be paid prior to the obligations under the notes and guarantees in the event of any foreclosure or bankruptcy event. Additionally, the intercreditor agreement generally permits each of the notes trustee and the collateral agent for the existing Second Lien Notes to independently enforce their liens on the collateral (provided that distributions received on enforcement are applied as provided in the intercreditor agreement). It is possible that disputes may occur between the holders of the notes and other secured parties as to the appropriate manner of pursuing enforcement remedies with respect to the collateral which may delay enforcement of the collateral, result in litigation and/or result in enforcement actions against the collateral that are not approved by the holders of the notes. See “Description of the Exchange Notes—Security” and “Description of the Exchange Notes—Intercreditor Agreement.”
Rights of holders of notes in the collateral may be adversely affected by bankruptcy proceedings.
The right of the collateral agent for the notes to repossess and dispose of the collateral securing the notes upon acceleration is likely to be significantly impaired by federal bankruptcy law if bankruptcy proceedings are commenced by or against us prior to or possibly even after the collateral agent has repossessed and disposed of the collateral. Under the U.S. Bankruptcy Code, a secured creditor, such as the collateral agent for the notes, is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from a debtor, without bankruptcy court approval. Moreover, bankruptcy law permits the debtor to continue to retain and to use collateral, and the proceeds, products, rents, or profits of the collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security, if and at such time as the court in its discretion determines, for any diminution in the value of the collateral as a result of the stay of repossession or disposition or any use of the collateral by the debtor during the pendency of the bankruptcy case. In view of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the notes could be delayed following commencement of a bankruptcy case, whether or when the collateral agent would repossess or dispose of the collateral, or whether or to what extent holders of the notes would be compensated for any delay in payment of loss of value of the collateral through the requirements of “adequate protection.” Furthermore, in the event the bankruptcy court determines that the value of the collateral is not sufficient to repay all amounts due on the notes, the holders of the notes would have “undersecured claims” as to the difference. Federal bankruptcy laws do not permit the payment or accrual of interest, costs, and attorneys’ fees for “undersecured claims” during the debtor’s bankruptcy case. Additionally, the trustee’s ability to foreclose on the collateral on your
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behalf may be subject to the consent of third parties, prior liens and practical problems associated with the realization of the trustee’s security interest in the collateral. Moreover, the debtor or trustee in a bankruptcy case may seek to avoid an alleged security interest in collateral for the benefit of the bankruptcy estate. It may successfully do so if the security interest is not properly perfected or was perfected within a specified period of time (generally 90 days) prior to the initiation of such proceeding. Under such circumstances, a creditor may hold no security interest and be treated as holding a general unsecured claim in the bankruptcy case. It is impossible to predict what recovery (if any) would be available for such an unsecured claim if we became a debtor in a bankruptcy case. While U.S. bankruptcy law generally invalidates provisions restricting a debtor’s ability to assume and/or assign a contract, there are exceptions to this rule which could be applicable in the event that we become subject to a U.S. bankruptcy proceeding.
Any future pledge of collateral may be avoidable in bankruptcy.
Any future pledge of collateral in favor of the trustee or collateral agent for the notes, including pursuant to security documents delivered after the date of the indenture governing the notes, may be avoidable in bankruptcy if certain events or circumstances exist or occur, including, among others, if:
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| the pledgor is insolvent at the time of the pledge, the pledge permits the holder of the notes to receive a greater recovery than if the pledge had not been given; and |
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| a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge, or, in certain circumstances, a longer period. |
Federal, state and foreign fraudulent transfer laws may permit a court to avoid the notes and the guarantees, subordinate claims in respect of the notes and the guarantees and require noteholders to return payments received. If this occurs, noteholders may not receive any payments on the notes.
Federal, state and foreign fraudulent transfer and conveyance statutes may apply to the issuance of the notes and the incurrence of any guarantees. Under federal bankruptcy law and comparable provisions of state fraudulent transfer or conveyance laws, which may vary from state to state and be different from other applicable foreign jurisdictions, the notes or guarantees could be avoided as a fraudulent transfer or conveyance if (1) we or any of the guarantors, as applicable, issued the notes or incurred the guarantees with the intent of hindering, delaying or defrauding creditors or (2) we or any of the guarantors, as applicable, received less than reasonably equivalent value or fair consideration in return for either issuing the notes or incurring the guarantees and, in the case of (2) only, one of the following is also true at the time thereof:
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| we or any of the guarantors, as applicable, were insolvent or rendered insolvent by reason of the issuance of the notes or the incurrence of the guarantees; |
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| the issuance of the notes or the incurrence of the guarantees left us or any of the guarantors, as applicable, with an unreasonably small amount of capital to carry on the business; |
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| we or any of the guarantors intended to, or believed that we or such guarantor would, incur debts beyond our or such guarantor’s ability to pay such debts as they mature; or |
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| we or any of the guarantors was a defendant in an action for money damages, or had a judgment for money damages docketed against us or such guarantor if, in either case, after final judgment, the judgment is unsatisfied. |
A court would likely find that we or a guarantor did not receive reasonably equivalent value or fair consideration for the notes or such guarantee if we or such guarantor did not substantially benefit directly or indirectly from the issuance of the notes or the applicable guarantee. As a general matter, value is given for a transfer or an obligation if, in exchange for the transfer or obligation, property is transferred or an antecedent debt is secured or satisfied. A debtor will generally not be considered to have received value in connection with a debt offering if the debtor uses the proceeds of that offering to make a dividend payment or otherwise retire or redeem equity securities issued by the debtor.
We cannot be certain as to the standards a court would use to determine whether or not we or the guarantors were solvent at the relevant time or, regardless of the standard that a court uses, that the issuance of the guarantees would not be further subordinated to our other debt or the debt of the guarantors. Generally, however, an entity would be considered insolvent if, at the time it incurred indebtedness:
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| the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets; |
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| the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or |
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| it could not pay its debts as they become due. |
If a court were to find that the issuance of the notes or the incurrence of the guarantee was a fraudulent transfer or conveyance, the court could avoid the payment obligations under the notes or such guarantee or further subordinate the notes or such guarantee to our presently existing and future indebtedness or of the related guarantor, or require the holders of the notes to repay any amounts received with respect to such guarantee. In the event of a finding that a fraudulent transfer or conveyance occurred, noteholders may not receive any repayment on the notes. Further, the avoidance of the notes could result in an event of default with respect to our other debt that could result in acceleration of such debt.
Although each guarantee entered into by the guarantors contains a provision intended to limit that guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent transfer, this provision may not be effective to protect those guarantees from being avoided under fraudulent transfer law, or may reduce that guarantor’s obligation to an amount that effectively makes its guarantee worthless.
In addition, different or additional fraudulent conveyance laws may exist in foreign jurisdictions which could result in the liens being avoided.
If the guarantees by the subsidiary guarantors are not enforceable, the notes would be effectively subordinated to all liabilities of the subsidiary guarantors, including trade payables.
The value of the collateral securing the notes and the guarantees may not be sufficient to secure post-petition interest.
In the event of a bankruptcy, liquidation, dissolution, reorganization or similar proceeding against us, holders of the notes will only be entitled to post-petition interest under the U.S. Bankruptcy Code to the extent that the value of their security interest in the collateral securing the notes and the guarantees is greater than their pre-bankruptcy claim. Holders of the notes that have a security interest in collateral with a value equal or less than their prebankruptcy claim will not be entitled to post-petition interest under the U.S. Bankruptcy Code. No appraisal of the fair market value of the collateral has been prepared in connection with the exchange offer and therefore the value of the noteholders’ interest in the collateral may not equal or exceed the principal amount of the notes.
The notes could be wholly or partially voided as a preferential transfer.
If we or any guarantor become the subject of a bankruptcy proceeding within 90 days after the date of the indenture (or, with respect to any insiders specified in bankruptcy law who are holders of the notes, within one year after we issue the notes), and the court determines that we were insolvent at the time of the closing (under the preference laws, we would be presumed to have been insolvent on and during the 90 days immediately preceding the date of filing of any bankruptcy petition), the court could find that the incurrence of the obligations under the notes involved a preferential transfer. In addition, to the extent that certain of our collateral is not perfected until after closing, such 90-day preferential transfer period would begin on the date of perfection. If the court determined that the granting of the security interest was therefore a preferential transfer, which did not qualify for any defense under bankruptcy law, then holders of the notes would be unsecured creditors with claims that ranked pari passu with all other unsecured creditors of the applicable obligor, including trade creditors. In addition, under such circumstances, the value of any consideration holders received pursuant to the notes, including upon foreclosure of the collateral securing the notes and the guarantees, could also be subject to recovery from such holders and possibly from subsequent assignees, or such holders might be returned to the same position they held as holders of the notes.
The notes currently have no established trading or other public market, and an active trading market may not develop for the notes. The failure of a market to develop for the notes could affect the liquidity and value of the notes and you may not be able to sell the notes readily, or at all, or at or above the price that you paid.
The notes constitute a new issue of securities with no established trading market. We do not intend to apply for the notes to be listed on any securities exchange or to arrange for quotation on any automated dealer quotation system. A market may not develop for the notes, and you may not be able to sell any of your notes at a particular time, at favorable prices or at all. As a result, we cannot assure you as to the liquidity of any trading market for any of the notes. Accordingly, you may be required to bear the financial risk of your investment in the notes indefinitely. If a trading market were to develop, future trading prices of the notes may be volatile and will depend on many factors, including:
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| our operating performance and financial condition or prospects; |
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| the prospects for a company in our industry generally; |
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| the number of holders of the notes; |
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| prevailing interest rates; |
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| the interest of securities dealers in making a market for the notes; and |
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| the market for similar securities and the overall securities market. |
The trading price of the notes may be volatile.
Historically, the market for non-investment grade debt, such as the notes, has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the notes. Any such disruptions could adversely affect the prices at which you may sell your notes. In addition, the notes may trade at a discount from the initial offering price of the notes, depending on the prevailing interest rates, the market for similar notes, our performance and other factors, many of which are beyond our control.
Risks Related to Our Business
The nature of our business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
We engage in exploration and development drilling activities, which are inherently risky. These activities may be unsuccessful for many reasons. In addition to a failure to find oil or natural gas, drilling efforts can be affected by adverse weather conditions (such as hurricanes and tropical storms in the U.S. Gulf Coast region), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of an oil or gas well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, could cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells could impede our efforts to replace reserves.
Our business involves a variety of operating risks, which include, but are not limited to:
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fires;
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explosions;
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blow-outs and surface cratering;
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uncontrollable flows of gas, oil and formation water;
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natural disasters, such as hurricanes and other adverse weather conditions;
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pipe, cement, subsea well or pipeline failures;
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casing collapses;
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mechanical difficulties, such as lost or stuck oil field drilling and service tools;
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abnormally pressured formations; and
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environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharge of toxic gases.
If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:
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injury or loss of life;
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severe damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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clean-up responsibilities;
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regulatory investigations and penalties;
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suspension of our operations; and
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repairs to resume operations.
Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.
Unlike other entities that are geographically diversified, all of our assets and operations are located in , and offshore of, south Louisiana and we do not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may:
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subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate; and
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result in our dependency upon a single or limited number of hydrocarbon basins.
In addition, the geographic concentration of our properties in the Gulf Coast region means that some or all of the properties could be affected should the region experience:
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severe weather, such as hurricanes and other adverse weather conditions;
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delays or decreases in production, the availability of equipment, facilities or services;
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delays or decreases in the availability of capacity to transport, gather or process production; and/or
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changes in the regulatory environment.
For example, our oil and gas properties were damaged, prior to our acquisition of those properties, by both Hurricanes Katrina and Rita, and, since our acquisition of the properties, by Hurricanes Gustav, Ike and Isaac. This damage required us, and the prior owners, to spend time and capital on inspections, repairs and debris removal. In accordance with industry practice, we maintain insurance against some, but not all, of these risks and losses. For additional information, please read “— Our insurance may not protect us against all of the operating risks to which our business is exposed.”
Because all or a number of the properties could experience many of the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.
Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices would adversely affect our financial results and impede our growth.
Our financial condition, revenues, profitability and carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. Commodity prices also affect our cash flow available for capital expenditures and our ability to access funds through the capital markets. The markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth.
Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:
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domestic and foreign supplies of oil and natural gas;
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price and quantity of foreign imports of oil and natural gas;
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actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;
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level of consumer product demand, including as a result of competition from alternative energy sources;
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level of global oil and natural gas inventories;
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political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
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weather conditions;
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technological advances affecting oil and natural gas production and consumption;
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overall U.S. and global economic conditions; and
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price and availability of alternative fuels.
Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us having to make downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.
Our actual recovery of reserves may differ from our proved reserve estimates.
This prospectus contains estimates of our proved oil and gas reserves. Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized in this prospectus. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, decommissioning liabilities and quantities of recoverable oil and gas reserves most likely will vary from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
We may be limited in our ability to maintain or book additional proved undeveloped reserves under the SEC’s rules.
We have included in this prospectus certain estimates of our proved reserves as of December 31, 2013 prepared in a manner consistent with our and our independent petroleum consultant’s interpretation of the SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies. Included within these SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped. During 2013, we expect to record an impairment charge relating to the reclassification of reserves previously classified as proved undeveloped reserves as a result of the failure to develop those reserves within five years of their being recorded as proved undeveloped. We may incur similar reclassifications and charges in the future if we are unable to develop some or all of our proved undeveloped reserves within five years of booking.
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As of December 31, 2012, approximately 75% of our total proved reserves were undeveloped and approximately 13% of our total proved reserves were developed non-producing. There can be no assurance that all of those reserves will ultimately be developed or produced.
While we have plans or are in the process of developing plans for exploiting and producing a majority of our proved reserves, there can be no assurance that we will have the resources to fully develop those reserves or that all of those reserves will ultimately be developed or produced. While we presently act as operator on substantially all of our properties, to the extent that we are not the operator with respect to our proved undeveloped reserves, we may not be in a position to control the timing of all development activities. Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reserves will ultimately be produced during the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.
Unless we replace crude oil and natural gas reserves, our future reserves and production will decline.
In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. While we were able to substantially increase our drilling and development budget in 2011 and 2012 using cash flow and funds provided by debt and equity offerings and we received additional debt financing during the fourth quarter of 2013, at December 31, 2013, we lacked a revolving credit facility and, accordingly, are dependent upon operating cash flow and funds on hand to support our drilling and development budget. In the absence of additional external financing, our ability to make planned capital investments to maintain and expand our reserves would be impaired to the extent cash flow from operations is reduced due to natural declines in production, declines in commodity prices or otherwise. Even if we have sufficient financing to support our optimum development plan, we may not be successful in exploring for, developing or acquiring additional reserves.
The nature and age of our wells may result in fluctuations in our production resulting from mechanical failures and other factors.
The majority of our wells have been in operation and have produced for many years. As a result of the age of those wells and their location in bay environments, those wells typically experience higher maintenance requirements than newer wells and wells located onshore. As a result, some of our wells may periodically be shut-in to perform maintenance or to restore optimal production levels or as a result of maintenance by third parties that operate facilities that serve our wells. Due to the periodic need to shut-in wells, we experience routine fluctuations in production levels with production declining below normal operating capacity during periods of maintenance. Further, because of their location in a bay environment, we sometimes experience delays in identifying and addressing production declines.
Our offshore operations involve special risks that could affect our operations adversely.
Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we are not intending to put in place business interruption insurance due to its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena.
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Our participation in, and realization of value from, shallow water ultra-deep shelf wells is subject to certain financing and operating risks that may prevent us from realizing the value of our deep reserve potential and expose us to delays, unexpected costs and other adverse financial consequences.
We have identified potential ultra-deep prospects underlying our transition zone acreage. The cost of exploration of such prospects, even when limited to our proportionate interest in such costs, is likely beyond that which we could fund from our current financial resources. Accordingly, we intend to seek additional partners to absorb a substantial portion of our share of such exploration costs. To that end, we have entered into discussions with various parties with respect to the potential formation of a joint venture to explore one or more ultra-deep prospects. We have not, as of December 31, 2013, entered into a definitive agreement with any prospective partner to fund or participate in the exploration of our ultra-deep prospects. In the event that we enter into such a joint venture arrangement but are unable to make satisfactory arrangements to fund our portion of exploration costs, our interests in some of our ultra-deep prospects may be substantially reduced or lost with little or no benefit from such interests accruing to our benefit. Further, the shallow water ultra-deep wells are expected to be some of the deepest wells ever drilled in the world and are subject to very high pressures and temperatures. The drilling, logging and completion techniques are near the limits of existing technologies. As a result, new technologies and techniques are being developed to deal with these challenges. The use of advanced drilling technologies involves a higher risk of technological failure and potentially higher costs. In addition, there can be delays in completion due to necessary equipment that is specially ordered to handle the challenges of ultra-deep wells. Even if we are able to participate in drilling ultra-deep wells there is no assurance that such wells will be commercially viable. Such wells are presently expected to be natural gas wells and, based on the current low price of natural gas, there is no assurance that the wells can be operated in an economically feasible manner even if successfully completed.
Our participation in, and realization of value from, Gulf of Mexico shelf prospects is subject to participation of partners in the financing and development of those prospects and subjects us to risk associated with operating under BOEMRE rules.
During 2013, we acquired four leases totaling 19,814 acres in the shallow Gulf of Mexico shelf. The leases are located in the federal waters of the Gulf of Mexico and are subject to rules and regulations of the BOEMRE. We have no history of developing and operating properties subject to BOEMRE regulation or in the deeper waters that characterize those leases and lack the financial resources to develop those prospects. Accordingly, we intend to seek partners in the development of such prospects which may entail farm-outs, promoted deals or other similar arrangements with partners having greater experience and financial resources to carry out such development and operating activities. If we are unable to secure partners to participate in such activities we may realize no value from the prospects and may lose our investment in those prospects. Even if we are able to secure necessary partners to fund, develop and operate those prospects, there is no guaranty that such activities will result in commercially viable wells.
Our insurance may not protect us against all of the operating risks to which our business is exposed.
We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Due to market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Consistent with industry practice, we are not fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations. Due to a number of catastrophic events in recent years, including Hurricanes Ivan, Katrina, Rita, Gustav, Ike and Isaac and the April 2010 Deep Water Horizon incident, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered damage from Hurricanes Ivan, Katrina, Rita, Gustav, Ike and Isaac. As a result, insurance costs for many operators in the Gulf Coast region have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is as severe, insurance underwriters may no longer insure assets in the Gulf Coast region against weather-related damage. In addition, we do not intend to put in place business interruption insurance due to its high cost. This insurance may not be economically available in the future, which could adversely impact business prospects in the Gulf Coast region and adversely impact our operations. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a vendor, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.
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Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.
We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than ours. We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases may be acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe will impact attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves.
This prospectus contains estimates of our future net cash flows from our proved reserves. We base the estimated discounted future net cash flows from our proved reserves on average prices for the preceding twelve-month period and costs in effect on the day of the estimate. However, actual future net cash flows from our natural gas and oil properties will be affected by factors such as:
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the volume, pricing and duration of our natural gas and oil hedging contracts;
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supply of and demand for natural gas and oil;
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actual prices we receive for natural gas and oil;
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our actual operating costs in producing natural gas and oil;
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the amount and timing of our capital expenditures and decommissioning costs;
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the amount and timing of actual production; and
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changes in governmental regulations and taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute exploration and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.
We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services may increase or decrease depending on the demand for services by other oil and gas companies. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.
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Market conditions or transportation impediments may hinder access to oil and gas markets, delay production or increase our costs.
Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities. In offshore operations, market access depends on the proximity of and our ability to tie into existing production platforms and, where those facilities are owned or operated by third parties, the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. Restrictions on our ability to sell our oil and natural gas may have several other adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possible loss of a lease due to lack of production. In the event that we encounter restrictions in our ability to tie our production to a gathering system, we may face considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues. In some cases, our wells may be tied back to platforms owned by parties with no economic interests in these wells. There can be no assurance that owners of such platforms will continue to operate the platforms. If the owners cease to operate the platforms or their processing equipment, we may be required to shut in the associated wells, which could adversely affect our results of operations.
We may not be the operator on all of our properties and therefore are not in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on such properties.
As we carry out our planned drilling program, we may not serve as operator of all planned wells. We currently operate over 98% of our proved reserves, but do not expect to operate any wells that may be drilled on ultra-deep prospects or the Gulf of Mexico shelf prospects acquired during 2013. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:
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the timing and amount of capital expenditures;
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the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;
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the operator’s expertise and financial resources;
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approval of other participants in drilling wells;
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selection of technology; and
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the rate of production of the reserves.
Each of these factors, and others, could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
We are exposed to trade credit risk in the ordinary course of our business activities.
We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Declines in the credit markets and the availability of credit or declines in equity values of our vendors, customers and counterparties, as well as declines in cash flow resulting from declines in commodity prices, may result in a significant reduction in our vendors, customers and counterparties liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could reduce our cash flows.
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We sell the majority of our production to a small number of customers.
Three customers accounted for approximately 81% of our total oil and natural gas revenues during the year ended December 31, 2012. Our inability to continue to sell our production to those customers, if not offset by sales with new or other existing customers, could have a material adverse effect on our business and operations.
Unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.
We may become responsible for unanticipated costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith is often referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated or the decommissioning be accelerated, such as can happen after a hurricane, such costs may exceed the value of reserves remaining at any particular time. We may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations. During 2012 and 2013, we incurred decommissioning costs in excess of our estimates and established reserve and we may incur costs in excess of our reserves in the future.
Lower oil and gas prices and other factors may result in impairments of our asset carrying values.
Under the successful efforts method of accounting, whenever circumstances indicate that an asset may be impaired, we are required to compare the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows are lower than the unamortized capitalized cost, an impairment charge is realized to reduce the capitalized cost to fair value. In computing future undiscounted cash flows of assets, we take into account estimates of future crude oil and natural gas prices as well as operating costs, anticipated production from proved reserves and other relevant data. Accordingly, a decline in oil and natural gas prices could cause a future write-down of capitalized costs and a non-cash impairment charge against future earnings.
Our success depends on dedicated and skillful management and staff, whose departure could disrupt our business operations.
Our success depends on our ability to retain and attract experienced engineers, geoscientists and other professional staff. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.
Risks Related to Our Risk Management Activities
If we place hedges on future production and encounter difficulties meeting that production, we may not realize the originally anticipated cash flows.
Our assets consist of a mix of reserves, with some being developed while others are undeveloped. To the extent that we sell the production of these reserves on a forward-looking basis but do not realize that anticipated level of production, our cash flow may be adversely affected if energy prices rise above the prices for the forward-looking sales. In this case, we would be required to make payments to the purchaser of the forward-looking sale equal to the difference between the current commodity price and that in the sales contract multiplied by the physical volume of the shortfall. There is the risk that production estimates could be inaccurate or that storms or other unanticipated problems could cause the production to be less than the amount anticipated, causing us to make payments to the purchasers pursuant to the terms of the hedging contracts.
Our price risk management activities could result in financial losses or could reduce our income, which may adversely affect our cash flows.
We enter into derivative contracts to reduce the impact of natural gas and oil price volatility on our cash flow from operations. Currently, we use a combination of natural gas and crude oil swap and physical arrangements to mitigate the volatility of future natural gas and oil prices received on our production.
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Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial decrease in our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:
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a counterparty may not perform its obligations under the applicable derivative instrument;
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production is less than expected;
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there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
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the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.
If we are unable to effectively manage the commodity price risk of our production if energy prices fall, we may not realize the anticipated cash flows from our assets.
During the third quarter of 2012, we instituted a hedging program in an effort to manage our commodity price risk. If we fail to effectively manage the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves. Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Moreover, our lack of a revolving credit facility may limit the scope and nature of commodity price risk management tools available to us. There is the possibility that we may be unable to find counterparties willing to enter into derivative arrangements with us or be required to either purchase relatively expensive put options, or commit to deliver future production, to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to make cash deposits available to counterparties as they mark to market these financial hedges. Proposed changes in regulations affecting derivatives may further limit or raise the cost, or increase the credit support required to hedge. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves.
Risks Related to Our Acquisition Strategy
Our acquisitions may be stretching our existing resources.
We acquired our principal properties in 2008 and may make acquisitions in the future. Future transactions may prove to stretch our internal resources and infrastructure. As a result, we may need to invest in additional resources, which will increase our costs. Any further acquisitions we make over the short term would likely intensify these risks.
We may be unable to successfully integrate the operations of the properties we acquire.
Integration of the operations of the properties we acquire with our existing business is a complex, time-consuming and costly process. Failure to successfully integrate the acquired businesses and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the acquired operations include, among other things:
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operating a larger organization;
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coordinating geographically disparate organizations, systems and facilities;
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integrating corporate, technological and administrative functions;
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diverting management’s attention from other business concerns;
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diverting financial resources away from existing operations;
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an increase in our indebtedness; and
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potential environmental or regulatory liabilities and title problems.
The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.
In addition, we face the risk of identifying, competing for and pursuing other acquisitions, which takes time and expense and diverts management’s attention from other activities.
We may not realize all of the anticipated benefits from our acquisitions.
We may not realize all of the anticipated benefits from our future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices.
The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.
Our business strategy includes acquisitions, which may include acquisitions of exploration and production companies, producing properties and undeveloped leasehold interests. The successful acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:
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acceptable prices for available properties;
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amounts of recoverable reserves;
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estimates of future oil and natural gas prices;
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estimates of future exploratory, development and operating costs;
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estimates of the costs and timing of plugging and abandonment; and
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estimates of potential environmental and other liabilities.
Our assessment of acquired properties will not reveal all existing or potential problems nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies. In the course of our due diligence, we may not physically inspect every well, platform or pipeline. Even if we physically inspect each of these, our inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. If an acquired property does not perform as originally estimated, we may have an impairment, which could have a material adverse effect on or financial position and results of operations.
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Risks Related to Our Indebtedness and Access to Capital and Financing
Our level of indebtedness may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities.
As of December 31, 2013, we had total indebtedness of approximately $179.8 million. Our leverage and the current and future restrictions contained in the agreements governing our indebtedness may reduce our ability to incur additional indebtedness, engage in certain transactions or capitalize on acquisition or other business opportunities. Our indebtedness and other financial obligations and restrictions could have financial consequences. For example, they could:
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impair our ability to obtain additional financing in the future for capital expenditures, potential acquisitions, general business activities or other purposes;
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increase our vulnerability to general adverse economic and industry conditions;
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result in higher interest expense in the event of increases in interest rates to the extent that our debt is at a variable rates of interest;
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have a material adverse effect if we fail to comply with financial and restrictive covenants in any of our debt agreements, including an event of default if such event is not cured or waived;
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require us to dedicate a substantial portion of future cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate requirements;
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limit our flexibility in planning for, or reacting to, changes in our business and industry; and
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place us at a competitive disadvantage to those who have proportionately less debt.
If we are unable to meet future debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity or sell assets. We may then be unable to obtain such financing or capital or sell assets on satisfactory terms, if at all.
To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control.
Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures and development and exploration efforts will depend on our ability to generate cash in the future. Our future operating performance and financial results will be subject, in part, to factors beyond our control, including interest rates and general economic, financial and business conditions. We cannot assure that our business will generate sufficient cash flow from operations or that future borrowings or other facilities will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs.
If we are unable to generate sufficient cash flow to service our debt, we may be required to:
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refinance all or a portion of our debt;
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obtain additional financing;
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sell some of our assets or operations;
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reduce or delay capital expenditures, research and development efforts and acquisitions; or
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revise or delay our strategic plans.
If we are required to take any of these actions, it could have a material adverse effect on our business, financial condition and results of operations. In addition, we cannot assure that we would be able to take any of these actions, that these actions would enable us to continue to satisfy our capital requirements or that these actions would be permitted under the terms of the our various debt instruments.
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The covenants in the indenture governing our senior notes impose restrictions that may limit our ability and the ability of our subsidiaries to take certain actions. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.
The indentures governing our senior notes contain various covenants that limit our ability and the ability of our subsidiaries to, among other things:
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incur dividend or other payment obligations;
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incur indebtedness and issue preferred stock; or
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sell or otherwise dispose of assets, including capital stock of subsidiaries.
If we breach any of these covenants, a default could occur. A default, if not waived, would entitle certain of our debt holders to declare all amounts borrowed under the breached indenture to become immediately due and payable, which could also cause the acceleration of obligations under certain other agreements and the termination of our credit facility. In the event of acceleration of our outstanding indebtedness, we cannot assure that we would be able to repay our debt or obtain new financing to refinance our debt. Even if new financing was made available to us, it may not be on terms acceptable to us.
We expect to have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.
We expect to make substantial capital expenditures for the acquisition, development, production, exploration and abandonment of oil and gas properties. Our capital requirements depend on numerous factors and we cannot predict accurately the timing and amount of our capital requirements. We have historically financed our capital expenditures through cash flow from operations and cash on hand, including cash received through multiple equity and debt offerings undertaken during 2011, 2012 and 2013. However, if our capital requirements vary materially from those provided for in our current projections, we may require additional financing to support future capital expenditures. At December 31, 2013, we lacked a revolving credit facility and had no existing commitments to provide financing if needed to support future capital requirements. A decrease in expected revenues or an adverse change in market conditions could make obtaining this financing economically unattractive or impossible.
The cost of raising money in the debt and equity capital markets may increase substantially while the availability of funds from those markets may diminish significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets may increase as lenders and institutional investors could increase interest rates, impose tighter lending standards, refuse to refinance existing debt at maturity at all or on terms similar to our current debt and, in some cases, cease to provide funding to borrowers.
An increase in our indebtedness, as well as the credit market and debt and equity capital market conditions discussed above could negatively impact our ability to secure, and remain in compliance with the financial covenants under, any revolving credit facility which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth as expected, we could be required to seek alternative financing, the terms of which may be less favorable to us, or not pursue growth opportunities.
Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations. We may also be unable to obtain sufficient credit capacity with counterparties to finance the hedging of our future crude oil and natural gas production which may limit our ability to manage price risk. As a result, we may lack the capital necessary to complete potential acquisitions, obtain credit necessary to enter into derivative contracts to hedge our future crude oil and natural gas production or to capitalize on other business opportunities.
Any future financial crisis may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable because of the deterioration of the capital and credit markets.
The recent credit crisis and related turmoil in the global financial systems had an impact on our business and our financial condition, and we may face challenges if economic and financial market conditions deteriorate in the future. Historically, we have used our cash flow from operations and funds provided by debt and equity offerings to fund our capital expenditures. A recurrence of the economic crisis could further reduce the demand for oil and natural gas and put downward pressure on the prices for oil and natural gas.
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The recent credit crisis also made it more difficult to obtain funding in the public and private capital markets. In particular, the cost of raising money in the debt and equity capital markets increased substantially while the availability of funds from those markets generally diminished significantly. Also, as a result of concerns about the general stability of financial markets and the solvency of specific counterparties, the cost of obtaining money from the credit markets increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity or on terms similar to existing debt or at all, or, in some cases, ceased to provide any new funding. A return of these conditions could materially and adversely affect our company.
Risks Related to Environmental and Other Regulations
Our operations are subject to environmental and other government laws and regulations that are costly and could potentially subject us to substantial liabilities.
Our oil and gas exploration, production, and related operations are subject to extensive rules and regulations promulgated by federal, state, and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.
All of the jurisdictions in which we operate generally require permits for drilling operations, drilling bonds, and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain jurisdictions also limit the rate at which oil and gas can be produced from our properties.
Our sales of oil and natural gas liquids are not presently regulated and are made at market prices. The price we receive from the sale of those products is affected by the cost of transporting the products to market. FERC regulations establish an indexing system for transportation rates for oil pipelines, which, generally, index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.
FERC has civil penalty authority to impose penalties for current violations. While our operations have not been regulated by FERC, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.
Our oil and gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:
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require the acquisition of a permit before drilling commences;
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restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;
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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
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impose substantial liabilities for pollution resulting from operations.
Failure to comply with these laws and regulations may result in:
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the imposition of administrative, civil and/or criminal penalties;
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incurring investigatory or remedial obligations; and
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•
the imposition of injunctive relief, which could limit or restrict our operations.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to be in compliance in all material respects with all applicable environmental laws and regulations, we cannot assure shareholders that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability.
Under certain environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, or if current or prior operations were conducted consistent with accepted standards of practice. Such liabilities can be significant, and if imposed could have a material adverse effect on our financial condition or results of operations.
We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.
Our sales of oil and natural gas, and any hedging activities related to such energy commodities, expose us to potential regulatory risks.
FERC holds statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil and natural gas, and any hedging activities related to these energy commodities, we are required to observe the market-related regulations enforced by these agencies, which hold enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and a number of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
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The adoption of financial reform legislation by Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), signed into law in 2010, requires the Commodities Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules and regulations relating to, among other things, the over-the-counter derivatives market. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. The financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require certain counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The final rules will be phased in over time according to a specified schedule which is dependent on the finalization of certain other rules to be promulgated jointly by the CFTC and the SEC. The Dodd-Frank Act and any new regulations could increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas liquids and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas liquids and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
If we are unable to acquire or renew permits and approvals required for operations, we may be forced to suspend or cease operations altogether.
The construction and operation of energy projects require numerous permits and approvals from governmental agencies. We may not be able to obtain all necessary permits and approvals, and as a result our operations may be adversely affected. In addition, obtaining all necessary permits and approvals may necessitate cash expenditures and may create a risk of expensive delays or loss of value if a project is unable to proceed as planned due to changing requirements or local opposition.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
President Obama and members of Congress have, on multiple occasions, advocated and proposed legislation that, if enacted, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. Several bills have been introduced in Congress that would implement these proposals. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
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THE EXCHANGE OFFER
Purpose of the Exchange Offer
We sold the outstanding notes in transactions that were exempt from or not subject to the registration requirements of the Securities Act. Accordingly, the outstanding notes are subject to transfer restrictions. In general, you may not offer or sell the outstanding notes unless either they are registered under the Securities Act or the offer or sale is exempt from or not subject to registration under the Securities Act and applicable state securities laws.
In connection with the sale of the outstanding notes, we entered into a registration rights agreement with the purchasers of the outstanding notes. We are offering the exchange notes under this prospectus in an exchange offer for the outstanding notes to satisfy our obligations under the registration rights agreement. The exchange offer will be open for at least 30 days (or longer, if required by applicable law). During the exchange offer period, we will exchange the exchange notes for all outstanding notes properly surrendered and not withdrawn before the expiration date. The exchange notes will be registered and the transfer restrictions, registration rights and provisions for additional interest relating to the outstanding notes will not apply to the exchange notes.
Resale of Exchange Notes
Based on no-action letters of the SEC staff issued to third parties, we believe that exchange notes may be offered for resale, resold and otherwise transferred by you without further compliance with the registration and prospectus delivery provisions of the Securities Act if:
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| you are not an “affiliate” of us or any of the subsidiary guarantors within the meaning of Rule 405 under the Securities Act; |
| • |
| such exchange notes are acquired in the ordinary course of your business; and |
| • |
| you do not intend to participate in a distribution of the exchange notes and you have no arrangement or understanding with any person or entity to participate in the distribution of the exchange notes. |
The SEC staff, however, has not considered the exchange offer for the exchange notes in the context of a no-action letter, and the SEC staff may not make a similar determination as in the no-action letters issued to these third parties.
If you tender in the exchange offer with the intention of participating in any manner in a distribution of the exchange notes, you
| • |
| cannot rely on such interpretations by the SEC staff; and |
| • |
| must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction. |
Unless an exemption from registration is otherwise available, any securityholder intending to distribute exchange notes must be covered by an effective registration statement under the Securities Act. The registration statement should contain the selling securityholder’s information required by Item 507 or 508, as applicable, of Regulation S-K under the Securities Act.
This prospectus may be used for an offer to resell, resale or other transfer of exchange notes only as specifically described in this prospectus. If you are a broker-dealer, you may participate in the exchange offer only if you acquired the outstanding notes as a result of market-making activities or other trading activities. Each broker-dealer that receives exchange notes for its own account in exchange for outstanding notes, where such outstanding notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge by way of the letter of transmittal that it will deliver this prospectus in connection with any resale of the exchange notes. Please read the section captioned “Plan of Distribution” for more details regarding the transfer of exchange notes.
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Terms of the Exchange Offer
Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any outstanding notes properly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer. We will issue exchange notes in principal amount equal to the principal amount of outstanding notes surrendered in the exchange offer. Outstanding notes may be tendered only for exchange notes and only in denominations of $2,000 and integral multiples of $1,000 in excess thereof.
The exchange offer is not conditioned upon any minimum aggregate principal amount of outstanding notes being tendered in the exchange offer.
As of the date of this prospectus, $54,600,000 in aggregate principal amount of 10.0% Senior Secured Notes due 2015 are outstanding. This prospectus is being sent to the registered holders of the outstanding notes. There will be no fixed record date for determining registered holders of outstanding notes entitled to participate in the exchange offer.
We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the rules and regulations of the SEC. Outstanding notes whose holders do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These outstanding notes will be entitled to the rights and benefits such holders have under the indenture governing the outstanding notes and the registration rights agreement.
We will be deemed to have accepted for exchange properly tendered outstanding notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the exchange notes from us.
If you tender outstanding notes in the exchange offer, you will be responsible for brokerage fees and commissions, transfer taxes and the fees and expenses of any legal counsel and any other advisors you engage with respect to the exchange of outstanding notes. Please read “— Fees and Expenses” for more details regarding fees and expenses that we expect to pay in connection with the exchange offer.
We will return any outstanding notes that we do not accept for exchange for any reason without expense to their tendering holders promptly after the expiration or termination of the exchange offer.
Expiration Date
The exchange offer will expire at 5:00 p.m., New York City time, on , 2014, unless, in our sole discretion, we extend it.
Extensions, Delays in Acceptance, Termination or Amendment
We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any outstanding notes by giving oral or written notice of such extension to the holders at any time until the exchange offer expires or terminates. During any such extensions, all outstanding notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.
To extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the holders of outstanding notes of the extension via a press release issued no later than 9:00 a.m. New York City time on the business day after the previously scheduled expiration date.
If any of the conditions described below under “— Conditions to the Exchange Offer” have not been satisfied, we reserve the right, in our sole discretion
| • |
| to delay accepting for exchange any outstanding notes, |
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| to extend the exchange offer, or |
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| to terminate the exchange offer, |
by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.
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Any such delay in acceptance, extension, termination or amendment will be followed promptly by oral or written notice thereof to holders of the outstanding notes. If we amend the exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The prospectus supplement will be distributed to holders of the outstanding notes. Depending upon the significance of the amendment and the manner of disclosure to holders, we will extend the exchange offer if it would otherwise expire during such period. If an amendment constitutes a material change to the exchange offer, including the waiver of a material condition, we will extend the exchange offer, if necessary, to remain open for at least five business days after the date of the amendment. In the event we offer any consideration for the outstanding notes or in the percentage of outstanding notes being sought by us, we will extend the exchange offer to remain open for at least 10 business days after the date we provide notice of such increase or decrease to the registered holders of outstanding notes.
Conditions to the Exchange Offer
We will not be required to accept for exchange, or exchange any exchange notes for, any outstanding notes if the exchange offer, or the making of any exchange by a holder of outstanding notes, would violate applicable law or SEC policy. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting outstanding notes for exchange in the event of such a potential violation.
We will not be obligated to accept for exchange the outstanding notes of any holder that has not made to us the representations described under “— Procedures for Tendering” and “Plan of Distribution” and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the exchange notes under the Securities Act.
Additionally, we will not accept for exchange any outstanding notes tendered, and will not issue exchange notes in exchange for any such outstanding notes, if at such time any stop order has been threatened or is in effect with respect to the exchange offer registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act of 1939.
We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any outstanding notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will promptly give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the outstanding notes.
These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times prior to the expiration of the exchange offer in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times prior to the expiration of the exchange offer.
Procedures for Tendering
To participate in the exchange offer, you must properly tender your outstanding notes to the exchange agent as described below. We will only issue exchange notes in exchange for outstanding notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the outstanding notes, and you should follow carefully the instructions on how to tender your outstanding notes. It is your responsibility to properly tender your outstanding notes. We have the right to waive any defects. However, we are not required to waive defects, and neither we nor the exchange agent is required to notify you of any defects in your tender.
There is no procedure for guaranteed later delivery of the outstanding notes.
Only a holder of record may tender outstanding notes in the exchange offer. To tender in the exchange offer, a holder must:
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| complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal; have the signature on the letter of transmittal guaranteed if the letter of transmittal so requires; and deliver the letter of transmittal or facsimile, together with all other documents required by such letter of transmittal, to the exchange agent prior to the expiration date; or |
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| comply with DTC’s Automated Tender Offer Program procedures described below. |
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In addition, either:
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| the exchange agent must receive, before expiration of the exchange offers, the tendered old notes along with the letter of transmittal; or |
| • |
| the exchange agent must receive, before expiration of the exchange offers, a properly transmitted agent’s message or a timely confirmation of book-entry transfer of old notes into the exchange agent’s account at DTC according to the procedure for book-entry transfer described below. |
To be tendered effectively, the exchange agent must receive any physical delivery of the letter of transmittal and other required documents at the address set forth below under the caption “—Exchange Agent” before expiration of the exchange offer. To receive confirmation of valid tender of outstanding notes, a holder should contact the exchange agent at the telephone number listed under the caption “—Exchange Agent.”
The tender by a holder that is not withdrawn before expiration of the exchange offer will constitute an agreement between that holder and us in accordance with the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal. If a holder tenders less than all of the outstanding notes held by such holder, such tendering holder should fill in the applicable box of the letter of transmittal. The amount of outstanding notes delivered to the exchange agent will be deemed to have been tendered unless otherwise indicated.
THE METHOD OF DELIVERY OF OUTSTANDING NOTES, THE LETTER OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE HOLDER’S ELECTION AND RISK. RATHER THAN MAIL THESE ITEMS, WE RECOMMEND THAT HOLDERS USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, HOLDERS SHOULD ALLOW SUFFICIENT TIME TO ASSURE DELIVERY TO THE EXCHANGE AGENT BEFORE EXPIRATION OF THE EXCHANGE OFFER. HOLDERS SHOULD NOT SEND THE LETTER OF TRANSMITTAL OR OUTSTANDING NOTES TO US. HOLDERS MAY REQUEST THEIR RESPECTIVE BROKERS, DEALERS, COMMERCIAL BANKS, TRUST COMPANIES OR OTHER NOMINEES TO EFFECT THE ABOVE TRANSACTIONS FOR THEM.
Any beneficial owner whose outstanding notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and who wishes to tender should contact the registered holder promptly and instruct it to tender on the owner’s behalf. If the beneficial owner wishes to tender on its own behalf, it must, prior to completing and executing the letter of transmittal and delivering its old notes, either:
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| make appropriate arrangements to register ownership of the outstanding notes in the owner’s name; or |
| • |
| obtain a properly completed bond power from the registered holder of outstanding notes. |
The transfer of registered ownership may take considerable time and may not be completed prior to the expiration date.
If the applicable letter of transmittal is signed by the record holder(s) of the outstanding notes tendered, the signature must correspond with the name(s) written on the face of the outstanding note without alteration, enlargement or any change whatsoever. If the applicable letter of transmittal is signed by a participant in DTC, the signature must correspond with the name as it appears on the security position listing as the holder of the outstanding notes.
A signature on a letter of transmittal or a notice of withdrawal must be guaranteed by an eligible guarantor institution. Rule 17Ad-15 under the Exchange Act describes eligible guarantor institutions as banks, brokers, dealers, municipal securities dealers, municipal securities brokers, government securities dealers, government securities brokers, credit unions, national securities exchanges, registered securities associations, clearing agencies and savings associations. The signature need not be guaranteed by an eligible guarantor institution if the outstanding notes are tendered:
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| by a registered holder who has not completed the box entitled “Special Registration Instructions” or “Special Delivery Instructions” on the letter of transmittal; or |
| • |
| for the account of an eligible institution. |
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If the letter of transmittal is signed by a person other than the registered holder of any outstanding notes, the outstanding notes must be endorsed or accompanied by a properly completed bond power. The bond power must be signed by the registered holder as the registered holder’s name appears on the outstanding notes and an eligible institution must guarantee the signature on the bond power.
If the letter of transmittal or any outstanding notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, these persons should so indicate when signing. Unless we waive this requirement, they should also submit evidence satisfactory to us of their authority to deliver the letter of transmittal.
The exchange agent and DTC have confirmed that any financial institution that is a participant in DTC’s system may use DTC’s Automated Tender Offer Program to tender. Participants in the program may, instead of physically completing and signing the letter of transmittal and delivering it to the exchange agent, transmit their acceptance of the exchange offers electronically. They may do so by causing DTC to transfer the outstanding notes to the exchange agent in accordance with its procedures for transfer. DTC will then send an agent’s message to the exchange agent. The term “agent’s message” means a message transmitted by DTC, received by the exchange agent and forming part of the book-entry confirmation, to the effect that:
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| DTC has received an express acknowledgment from a participant in its Automated Tender Offer Program that is tendering outstanding notes that are the subject of the book-entry confirmation; |
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| the participant has received and agrees to be bound by the terms of the letter of transmittal; and |
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| the agreement may be enforced against the participant. |
Determinations Under the Exchange Offer. We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered outstanding notes and withdrawal of tendered outstanding notes. Our determination will be final and binding. We reserve the absolute right to reject any outstanding notes not properly tendered or any outstanding notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular outstanding notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of outstanding notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of outstanding notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of outstanding notes will not be deemed made until such defects or irregularities have been cured or waived. Any outstanding notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder promptly following the expiration date of the exchange.
When We Will Issue Exchange Notes. In all cases, we will issue exchange notes for outstanding notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:
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| outstanding notes or a timely book-entry confirmation that outstanding notes have been transferred into the exchange agent’s account at DTC; and |
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| a properly completed and duly executed letter of transmittal and all other required documents or a properly transmitted agent’s message. |
Your Representations to Us. By signing the letter of transmittal, each tendering holder of outstanding notes will represent to us that, among other things:
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| the holder has full power and authority to tender, sell, assign and transfer the outstanding notes and to acquire the exchange notes issuable upon the exchange of the tendered outstanding notes, and when the same are accepted for exchange, the Company will acquire good and unencumbered title to the tendered outstanding notes, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claim; |
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| any exchange notes that the holder receives will be acquired in the ordinary course of its business; |
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| the holder has no arrangement or understanding with any person or entity to participate in the distribution of the exchange notes; |
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| if the holder is not a broker-dealer, it is not engaged in and does not intend to engage in the distribution of the exchange notes; |
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| if the holder is a broker-dealer that will receive exchange notes for its own account in exchange for outstanding notes that were acquired as a result of market-making activities or other trading activities, it will deliver a prospectus, as required by law, in connection with any resale of those exchange notes (see “Plan of Distribution”); and |
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| the holder is not an “affiliate” as defined in Rule 405 of the Securities Act, of us or if the holder is an affiliate, it will comply with any applicable registration and prospectus delivery requirements of the Securities Act. |
Book-Entry Transfers
The exchange agent will make a request to establish an account with respect to the outstanding notes at DTC for purposes of the exchange offers promptly after the date of this prospectus. Any financial institution participating in DTC’s system may make book-entry delivery of outstanding notes by causing DTC to transfer outstanding notes into the exchange agent’s account at DTC in accordance with DTC’s procedures for transfer.
Withdrawal of Tenders
Except as otherwise provided in this prospectus, holders of outstanding notes may withdraw their tenders at any time before expiration of the exchange offer.
For a withdrawal to be effective:
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| the exchange agent must receive a written notice of withdrawal, which may be by telegram, telex, facsimile transmission or letter, at one of the addresses set forth below under the caption “—Exchange Agent”; or |
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| holders must comply with the appropriate procedures of DTC’s Automated Tender Offer Program system. |
Any notice of withdrawal must:
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| specify the name of the person who tendered the outstanding notes to be withdrawn; |
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| identify the outstanding notes to be withdrawn, including the principal amount of the outstanding notes to be withdrawn; and |
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| where certificates for outstanding notes have been transmitted, specify the name in which the outstanding notes were registered, if different from that of the withdrawing holder. |
If certificates for outstanding notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of those certificates, the withdrawing holder must also submit:
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| the serial numbers of the particular certificates to be withdrawn; and |
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| a signed notice of withdrawal with signatures guaranteed by an eligible institution, unless the withdrawing holder is an eligible institution. |
If outstanding notes have been tendered pursuant to the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn outstanding notes and otherwise comply with the procedures of the facility.
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We will determine all questions as to the validity, form and eligibility, including time of receipt, of notices of withdrawal, and our determination shall be final and binding on all parties. We will deem any outstanding notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer. We will return any outstanding notes that have been tendered for exchange but that are not exchanged for any reason to their holder without cost to the holder. In the case of outstanding notes tendered by book-entry transfer into the exchange agent’s account at DTC according to the procedures described above, those outstanding notes will be credited to an account maintained with DTC for outstanding notes, as soon as practicable after withdrawal, rejection of tender or termination of the exchange offers. You may retender properly withdrawn outstanding notes by following one of the procedures described under the caption “—Procedures for Tendering” above at any time on or before expiration of the exchange offer.
Fees and Expenses
We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by e-mail, telephone or in person by our officers and regular employees and those of our affiliates.
We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.
We will pay the cash expenses to be incurred in connection with the exchange offer. They include:
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| SEC registration fees; |
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| fees and expenses of the exchange agent and trustee; |
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| accounting and legal fees and printing costs; and |
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| related fees and expenses. |
Transfer Taxes
Each tendering holder will pay all transfer taxes, if any, applicable to the exchange of outstanding notes under the exchange offer.
Consequences of Failure to Exchange
If you do not exchange your outstanding notes for exchange notes under the exchange offer, the outstanding notes you hold will continue to be subject to the existing restrictions on transfer. In general, you may not offer or sell the outstanding notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not intend to register outstanding notes under the Securities Act unless the registration rights agreement requires us to do so.
Any tenders of outstanding notes under the exchange offer will reduce the principal amount of the currently outstanding notes. Due to the corresponding reduction in liquidity, this may have an adverse effect upon, and increase the volatility of, the market price of any currently outstanding notes that you continue to hold following completion of the exchange offer.
Accounting Treatment
We will record the exchange notes in our accounting records at the same carrying value as the outstanding notes. This carrying value is the face value of the outstanding notes, less the original issue discount (net of amortization) as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer, other than the recognition of the fees and expenses of the offering as stated under “— Fees and Expenses.”
Other
Participation in the exchange offer is voluntary, and you should consider carefully whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.
We may in the future seek to acquire untendered outstanding notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any outstanding notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered outstanding notes.
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Exchange Agent
The Bank of New York Mellon Trust Company, N.A. has been appointed as exchange agent for the exchange offer. You should direct questions and requests for assistance and requests for additional copies of this prospectus or of the letter of transmittal or the notice of withdrawal to the exchange agent addressed as follows:
THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.
c/o The Bank of New York Mellon Trust Corporation
Corporate Trust Operations – Reorganization Unit
111 Sanders Creek Parkway
East Syracuse, NY 13057
Attention: Dacia Brown-Jones
Facsimile Transmission
(732) 667-9408
Confirm by Telephone:
(315) 414-3349
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USE OF PROCEEDS
The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any cash proceeds from the issuance of the exchange notes in the exchange offer. In consideration for issuing the exchange notes as contemplated by this prospectus, we will receive outstanding notes in a like principal amount. The form and terms of the exchange notes are identical in all respects to the form and terms of the outstanding notes, except the exchange notes do not include certain transfer restrictions, registration rights or provisions for additional interest. Outstanding notes surrendered in exchange for the exchange notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the exchange notes will not result in any change in our outstanding indebtedness.
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MANAGEMENT DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We are an independent oil and natural gas company engaged in the acquisition, development, exploitation, exploration and production of crude oil and natural gas properties. Our lease holdings totaled 51,890 acres at September 30, 2013, comprised of our principal producing properties covering 32,076 acres in the transitional coastline and protected in-bay environment on parish and state leases of south Louisiana and an additional 19,814 acres of leases in the shallow Gulf of Mexico shelf.
At September 30, 2013, we operated or had interests in 94 producing wells and our principal properties covered approximately 51,890 gross/net acres, 31,031 acres, or 60% of the total, of which were held by production without near-term lease expirations, across 10 fields in the transitional coastline and protected in-bay environment on parish and state leases in south Louisiana as well as in the shallow Gulf of Mexico. We own approximately 100% working interest in all our properties, with the only exception being a single well where we have an overriding royalty interest. Our net revenue interests in our properties range from 69% to 82%, with our average net revenue interest on a net acreage leasehold basis being approximately 75%. We operate over 99% of the wells that comprise our PV-10, enabling us to effectively exercise management control of our operating costs, capital expenditures and the timing and method of development of our properties.
Recent Developments
The following significant events, among others, affected our operations and financial position during 2012 and 2013:
Drilling and Development Activities
During the nine months ended September 30, 2013 and fiscal 2012, we invested $28.6 million and $59.8 million, respectively, in our drilling and development program and infrastructure projects, summarized as follows:
Development Drilling. During the nine months ended September 30, 2013 and fiscal 2012, we drilled four and three development wells, respectively.
The SL 195QQ-202 “Jupiter” well, in Grand Bay Field, was spud in July 2012 and completed in August 2012. The well reached total depth of 9,688 feet MD/TVD and encountered 104 feet of net pay in 15 sands between 5,516-9,042 feet and was completed in the 15 sand.
The SL 20433-1 “North Tiger” well, in Breton Sound 18 Field, was spud in July 2012 and completed in October 2012. The well reached total depth of 9,532 feet MD/9,300 feet TVD and encountered 59 feet of net pay in 6 sands and was completed as a dual producer.
The SL 3763-14 “Mesa Verde” well, in Vermilion 16 Field, was spud in May 2012 and completed in October 2012. The well reached a total depth of 16,258 feet MD/ TVD and encountered up to 15 potentially productive intervals, including the Marg A, LF, Rob 54 and Amph B sands between 11,333-15,890 feet and was completed in the LF-H sand.
The “Rocky” well, in Breton Sound 32 Field, was spud and completed in July 2013. The well targeted an elongated ridge, offsetting the SL 1227 #21 and #22 wells in the 5,800’ sand, which is the main producing reservoir in the Breton Sound 32 field. A seventy-degree pilot hole was drilled followed by a sidetrack with a 750’ lateral completion. This well was our first horizontal well.
The “Zeke” well, in Breton Sound 32 Field, was spud and completed in August 2013. The well also targeted the same 5,800’ sand as the Rocky well but in a separate structure to the south-east and was completed as a high angle (82 degrees) directional. The Zeke well also established a previously unbooked uphole recompletion opportunity in the overlying 5,750’ sand, which also produces within the field.
The MP47 SL 195QQ-25 “Roux Toux” well in Main Pass 47 Field, was spud and completed in February 2013. The well reached total depth of 8,453 feet MD/8,000 feet TVD and was completed in the 3A sand.
The SL 195QQ-209 “Buddy” well, in Grand Bay Field, was spud in December 2012 and completed in January 2013. The well reached total depth of 6,820 feet MD/ TVD and encountered and was completed in the 3A sand.
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Recompletion and Workover Program. During the nine months ended September 30, 2013, we carried out 18 recompletions and 9 workovers. Fourteen of the recompletions and all of the workovers were successful with one recompletion still in progress at the end of the period.
During 2012, we carried out 12 recompletions and 16 workovers. Eleven of the recompletions and all of the workovers were successful.
Infrastructure Program. During the nine months ended September 30, 2013 and fiscal 2012, we invested $4.9 million and $3.5 million, respectively, in infrastructure improvements and additions to support existing production and anticipated increases in production.
Drilling and Development Plans. We have an extensive inventory of drilling opportunities, including numerous proved behind pipe and proved undeveloped opportunities as well as a number of exploratory opportunities. Our near term development plans are focused on proved undeveloped opportunities and conversion of PDNP opportunities.
In addition to our program of proved undeveloped, PDNP, recompletion and workover opportunities, during 2013 we continued efforts to protect, and secure partners for the exploration and development of, ultra-deep prospects in our Grand Bay and Vermilion 16 fields and acquired four leases totaling 19,814 acres in the shallow Gulf of Mexico shelf. We continue to monitor ongoing ultra-deep exploratory projects and to conduct high level discussions with potential partners in an ultra-deep drilling program should the existing exploratory projects prove successful. We also intend to seek partners to develop and operate the shallow Gulf of Mexico shelf prospects via farm-outs, promoted deals or other similar arrangements. As of December 31, 2013, we had not yet entered into a joint venture, or other, agreement with respect to exploratory drilling of our ultra-deep prospects or development of our shallow Gulf of Mexico shelf prospects.
We continually evaluate our holdings with a view to optimizing our drilling and development plans based on ongoing development efforts, new geological and operating data, identification or acquisition of new opportunities and other factors. Accordingly, our drilling and development plans are fluid and subject to continuous revision and may vary from the plans described herein.
Effects of Hurricane Isaac and Tropical Storm Karen
Hurricane Isaac resulted in a disruption of production and the shut-in of 100% of our wells for a period of 17 days beginning August 26 and ending September 11, 2012 and reduced production while wells were brought back on line over the balance of 2012. The delay in returning field to productive status was primarily attributable to delays in third party pipeline transportation. We experienced minimal damage to our asset base and estimate total gross repair cost at $2.8 million, of which $2.0 million was covered by insurance. As of December 31, 2012, substantially all repairs arising from Hurricane Isaac had been completed and all of the wells had been returned to productive status. The hurricane also caused delays in the installation of the flowlines and facility infrastructure required for the North Tiger (SL 20433 #1/1D) well, which delayed our initial production startup by approximately 30 days, and pushed back a number of wells in our development schedule.
In early October 2013, we were substantially 100% shut-in for a day as pipeline operators and other third party service providers temporarily ceased operations in the Gulf of Mexico as a precaution prior to the arrival of Tropical Storm Karen. No material damage was sustained as a result of the storm but it took five days to bring our properties back to full production. As a result, we experienced some deferral of production and associated revenues during the fourth quarter of 2013.
Leasehold and Seismic Activity
Gulf of Mexico Shelf Acreage. In 2013, we bid on and were awarded four leases, with seismic maps included, totaling 19,814 acres in the Central Gulf of Mexico Lease Sale 227. The acreage is in the shallow Gulf of Mexico shelf in water depths of 13 to 77 feet. Two of the leases are in the Vermilion area and two of the leases are in the Ship Shoal area. Lease bonuses on the prospects totaled $880,000 and first year annual rentals total $138,698. Additionally, we paid a prospect fee of $450,000 to a third party consultant.
Louisiana State Leases. In September 2013, we acquired an additional 857.96 acres under two Louisiana state leases in Breton Sound 18, 19 and 32 fields. The leasehold acreage is contiguous with our existing lease holdings in Breton Sound 18 and 32 fields, is close to existing facilities and pipeline infrastructure and in water depths of less than 20 feet. The leases have a primary term of three years and are subject to a 21% royalty burden. Lease bonuses on the acreage totaled $225,620. Annual rentals on the leases total $94,755 during the primary term.
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During the third quarter of 2013, a lease in Little Bay Field terminated when we determined to temporarily abandon operations, resulting in an impairment charge of $2.2 million. In November 2013, we acquired a new three year lease covering acreage in Little Bay Field, including the acreage and associated well and reserves lost during the third quarter of 2013. Lease bonuses on the acreage totaled $86,026. Annual rentals on the lease total $37,171 and the lease bears a 25% royalty.
Hedges
During the quarter ended September 30, 2012, we resumed our hedging program under which, in the normal course of business, we periodically enter into commodity derivative transactions, including fixed price and ratio swaps to mitigate exposure to commodity price movements, but not for trading or speculative purposes.
As of September 30, 2013, we had in place fixed price swaps covering an aggregate of 197,250 barrels of oil over the period beginning October 1, 2013 and ending March 31, 2014, at prices ranging from $105.18 to $109.20 per barrel.
In October 2013, we received $620,500 in proceeds for the sale of crude oil call options. The options provided for a premium of $6.80 per Bbl for a total of 91,250 Bbls. The call options cover 250 Bbls per day beginning on April 1, 2014 and ending on March 31, 2015 at an option strike price of $103.30. The short crude oil call option, when combined with the Company’s long production position, represents a “covered call”, and creates a $103.30 per Bbl ceiling on the price to be received during the covered period for the related production.
Compensation
Our board of directors has adopted an Annual Incentive Program which is intended to establish potential bonus payouts tied to satisfaction of performance criteria and established broad company performance criteria. $0 and $190,553 of compensation expense was reported during nine months ended September 30, 2013 and fiscal 2012, respectively, based on accrual of estimated bonus payments under the program.
In June 2013, our board of directors approved new employment agreements for our two principal officers, Thomas Cooke and Andy Clifford. Pursuant to the new employment agreements, (i) the annual base salary of Messrs. Cooke and Clifford was increased from its then current level of $305,000 by 4%, to $317,200, on July 1, 2013 and increases by 4% on July 1 of each succeeding year; (ii) the automobile allowance of Messrs. Cooke and Clifford was modified to either provide a company vehicle or pay a monthly automobile allowance, which allowance remains $700 per month for Mr. Clifford and was increased to $950 per month for Mr. Cooke; additionally, beyond repair and maintenance costs previously paid by the company, the automobile allowance has been revised to cover all costs of operating a vehicle; (iii) the expense reimbursement provisions were modified to clarify that the company will pay all incremental costs associated with maintenance of home offices by Messrs. Cooke and Clifford, including costs of internet service, telephone and facsimile service and, with respect to Mr. Clifford, a home workstation; (iv) travel pay in the amount of $200 per day was added for each overnight stay or out-of-town travel of twenty-four hours exclusively for business purposes; (v) Messrs. Cooke and Clifford each received options to purchase 250,000 shares of common stock exercisable at $3.00 per share for a term of five years and vesting on a quarterly basis over eight quarters; (vi) in the event of termination of employment due to death or disability, we will continue to pay base salary to the executive or his estate for a period of twelve months; and (vii) in the event of termination of employment by the company without cause or by the executive for “good reason”, we will pay a lump sum to the executive in an amount equal to two times the base salary and bonus paid during the twelve months immediately preceding termination and shall continue to provide health insurance for a period of twenty-four months.
Stock Option Activity
During 2012, we granted stock options to purchase an aggregate of 105,000 shares of common stock to non-employee directors. The options are exercisable at $6.65 per share, had a term of seven years and vest 50% on the grant date and 50% one year from the grant date.
In addition, during 2012, we granted stock options purchase an aggregate of 5,000 shares of common stock to a non-executive employee. The options are exercisable at $6.40 per share, had a term of seven years and vest 50% on the grant date and 50% one year from the grant date.
As a result of the stock option grants during 2012, we recorded $1,205,919 of compensation charges that are reflected in general and administrative expense. During 2012, a total of 75,000 stock options were forfeited.
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During the nine months ended September 30, 2013, we granted an aggregate of 830,000 stock options to various employees, officers and directors at exercise prices ranging from $1.53 to $3.00 per share.
We recorded $233,132 and $769,427 of compensation charges that are reflected in general and administrative expense for the three and nine months ended September 30, 2013 and are attributable to equity grants during 2013 and prior years.
As of September 30, 2013, total compensation cost related to unvested stock option awards not yet recognized in earnings was approximately $0.8 million, which is expected to be recognized over a weighted average period of approximately 0.7 years.
Share Issuances
During 2013, we sold 6,500 shares of common stock for $9,945 pursuant to the exercise of outstanding stock options and 35,000 shares for $13,850 pursuant to the exercise of outstanding stock warrants.
Sale of 10% Senior Secured Notes
On November 22, 2013, we, and our several wholly-owned subsidiaries (the “Guarantors”), completed the issuance and sale to two institutional accredited investors (the “Purchasers”) of $54.6 million in aggregate principal amount of its 10.0% Senior Secured Notes due 2015 (the “First Lien Notes”).
The First Lien Notes were issued pursuant to Purchase Agreements, and under an Indenture (the “First Lien Indenture”), by and among the Company, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (the “First Lien Trustee”). The First Lien Notes are our senior secured obligations and are fully and unconditionally guaranteed (the “Guarantees”) on a senior secured basis by the Guarantors and will rank equally in right of payment with our, and the Guarantors’, existing and future senior indebtedness and senior in right of payment to Second Lien Notes (as defined below).
The purchase price for the First Lien Notes and Guarantees was 100% of their principal amount. We received net proceeds from the issuance and sale of the First Lien Notes of approximately $25.4 million, after commissions and estimated offering expenses, and the surrender for retirement by the Purchasers of $27.3 million in face amount of 12½% Senior Secured Notes (the “Second Lien Notes”).
The First Lien Notes mature on December 31, 2015, and interest, accruing at 10% per annum, is payable on the First Lien Notes on March 31, June 30, September 30 and December 31 of each year, commencing December 31, 2013.
We have the option to redeem all or a portion of the First Lien Notes at any time at 100% of the principal amount to be redeemed plus accrued and unpaid interest. Upon the occurrence of a change of control, we are required to offer to purchase the First Lien Notes at a price equal to 101% of the aggregate principal amount of First Lien Notes repurchased plus accrued and unpaid interest. Further, upon the occurrence of certain asset sales, we are required to provide notice of the same and are required to offer to purchase a defined portion of the First Lien Notes at a price equal to 100% of the principal amount of First Lien Notes repurchased plus accrued and unpaid interest.
The First Lien Indenture restricts our ability and the ability of our restricted subsidiaries to: (i) transfer or sell assets; (ii) make loans or investments; (iii) pay dividends, redeem subordinated indebtedness or make other restricted payments; (iv) incur or guarantee additional indebtedness or issue disqualified capital stock; (v) create or incur certain liens; (vi) incur dividend or other payment restrictions affecting certain subsidiaries; (vii) consummate a merger, consolidation or sale of all or substantially all of our assets; (viii) enter into transactions with affiliates; and (ix) engage in business other than the oil and gas business. These covenants are subject to a number of important exceptions and qualifications.
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The First Lien Indenture provides that each of the following is an Event of Default: (i) default for 30 days in the payment when due of interest on the First Lien Notes; (ii) default in payment when due at maturity, upon redemption or otherwise, of the principal of, or premium, if any, on the First Lien Notes; (iii) failure by us or any of our restricted subsidiaries to comply with certain covenants relating to merger, consolidation or sale of assets; (iv) failure by us or any of our restricted subsidiaries to comply for 60 days after notice with certain provisions under the First Lien Indenture; (v) default under any mortgage, indenture or similar instrument of indebtedness by us or any of our restricted subsidiaries, if the indebtedness aggregates $5 million or more, and that default: (a) is caused by a failure to pay principal of, or interest or premium, if any, on such indebtedness prior to the expiration of the grace period for such indebtedness or (b) results in the acceleration of such indebtedness prior to its stated maturity; (vi) failure by us or any of our restricted subsidiaries to pay final judgments aggregating in excess of $5 million, which judgments are not paid, discharged or stayed for a period of 60 days; (vii) any First Lien Note guarantee ceases to be in full force and effect, other than in accordance with the terms of the First Lien Indenture, or a guarantor of the First Lien Notes denies or disaffirms its obligations under its First Lien Note guarantee; (viii) any security document ceases to be in full force and effect in all material respects or ceases to give the collateral agent the rights, powers and privileges purported to be created therein with respect to any collateral having a fair market value in excess of $1 million or we or any of the Guarantors contest the effectiveness, validity or enforceability of any of the security documents; and (ix) certain events of bankruptcy or insolvency described in the Indenture with respect to our company or any of our significant subsidiaries. In the case of an Event of Default arising from certain events of bankruptcy or insolvency with respect to our company, certain restricted subsidiaries or certain groups of restricted subsidiaries, all outstanding First Lien Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the Trustee or the holders of at least 25% in principal amount of the then outstanding First Lien Notes may declare all the First Lien Notes to be due and payable immediately.
In connection with the issuance and sale of the First Lien Notes, we, the First Lien Trustee and The Bank of New York Mellon Trust Company, N.A., in its capacity as trustee and collateral under the Second Lien Documents (as defined below)(the “Second Lien Trustee”) entered into an Intercreditor Agreement (the “Intercreditor Agreement”). Pursuant to the Intercreditor Agreement, parties agreed that the lien with respect to collateral securing the First Lien Indenture and related First Lien Notes and Guarantees (the “First Lien Obligations”) shall be senior in right, priority, operation, effect and all other respects to any lien with respect to collateral securing the obligations under that certain Indenture dated as of June 12, 2011, as supplemented or amended from time to time thereafter (the “Second Lien Indenture”), by and among our company, the Guarantors named therein and the Second Lien Trustee, and the related Second Lien Notes in the aggregate amount of $152.5 million (the “Second Lien Obligations”).
In connection with the issuance and sale of the First Lien Notes, we and the Guarantors entered into a registration rights agreement (the “Registration Rights Agreement”) with the Purchasers. Pursuant to the Registration Rights Agreement, we and the Guarantors agreed to file a registration statement with the Securities and Exchange Commission so that holders of the First Lien Notes can exchange the First Lien Notes for registered notes that have substantially identical terms as the First Lien Notes. In addition, we and the Guarantors agreed to exchange the guarantee related to the First Lien Notes for a registered guarantee having substantially the same terms as the original guarantee. We filed the required registration statement in January 2014 and the registration statement has since been declared effective and the exchange completed, satisfying our obligations under the Registration Rights Agreement.
Sale of 12½% Senior Secured Notes
In December 2012, we issued an additional $25.0 million of our Second Lien Notes. The Second Lien Notes are our senior secured obligations and are fully and unconditionally guaranteed on a senior secured basis by the Guarantors and rank equally in right of payment with our and the Guarantors’ existing and future senior indebtedness. The Second Lien Notes mature on July 1, 2016, and interest is payable on the notes on January 1 and July 1 of each year. We have the option to redeem all or a portion of the Second Lien Notes at any time on or after January 1, 2014 at the redemption prices specified in the Indenture pursuant to which the Second Lien Notes were issued plus accrued and unpaid interest. In conjunction with our issuance of $54.6 million in principal amount of First Lien Notes, we retired $27.3 million in face amount of Second Lien Notes and the First Lien Trustee and Second Lien Trustee entered into the Intercreditor Agreement pursuant to which the First Lien Notes are senior in right, priority, operation and effect to the lien securing the Second Lien Note.
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Critical Accounting Policies
We prepare our consolidated financial statements in this report using accounting principles that are generally accepted in the United States (“GAAP”). GAAP represents a comprehensive set of accounting and disclosure rules and requirements. We must make judgments, estimates, and in certain circumstances, choices between acceptable GAAP alternatives as we apply these rules and requirements. The most critical estimate we make is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion, and amortization of oil and gas properties and the estimate of the impairment of our oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future net cash flows.
Estimated Oil and Gas Reserves
The evaluation of our oil and gas reserves is critical to management of our operations and ultimately our economic success. Decisions such as whether development of a property should proceed and what technical methods are available for development are based on an evaluation of reserves. These oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation, evaluating impairment and estimating the life of our producing oil and gas properties in our asset retirement obligations. Our proved reserves are classified as either proved developed or proved undeveloped. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves expected to be recovered from new wells from undrilled proven reservoirs or from existing wells where a significant major expenditure is required for completion and production. We also report probable reserves and possible reserves, each of which reflects a lower degree of certainty of realization than proved reserves.
Independent reserve engineers prepare the estimates of our oil and gas reserves presented in this report based on guidelines promulgated under GAAP and in accordance with the rules and regulations of the SEC. The evaluation of our reserves by the independent reserve engineers involves their rigorous examination of our technical evaluation and extrapolations of well information such as flow rates and reservoir pressure declines as well as other technical information and measurements. Reservoir engineers interpret these data to determine the nature of the reservoir and ultimately the quantity of proved, probable and possible oil and gas reserves attributable to a specific property. Our proved reserves in this report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the proved reserves will be produced, the timing and ultimate recovery can be effected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir, or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices, or production equipment/facility capacity.
Standardized measure of discounted future net cash flows
The standardized measure of discounted future net cash flows relies on these estimates of oil and gas reserves using commodity prices and costs. Commodity prices are based on the average prices as measured on the first day of each of the last twelve calendar months. In our 2012 year-end reserve report, we used an average oil price of $106.51 per Bbl, and a natural gas price of $5.13 per Mcf which includes adjustments by property for energy content, quality, transportation fees, and regional price differentials. While we believe that future operating costs can be reasonably estimated, future prices are difficult to estimate since the market prices are influenced by events beyond our control. Future global economic and political events will most likely result in significant fluctuations in future oil and gas prices.
Revenue Recognition
We recognize oil and gas revenue from interests in producing wells as the oil and gas is sold. Revenue from the purchase, transportation, and sale of natural gas is recognized upon completion of the sale and when transported volumes are delivered. We recognize revenue related to gas balancing agreements based on the sales method. Our net imbalance position at December 31, 2012 was immaterial.
44
Derivative Instruments
We account for derivative activities by applying authoritative accounting and reporting guidance which requires that every derivative instrument be recorded on the balance sheet as either an asset or a liability measured at its fair value and that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Substantially all of the derivative instruments that we utilize are to manage the price risk attributable to our expected oil and gas production. We have elected not to designate price risk management activities as accounting hedges under the accounting guidance and, accordingly, account for them using the mark-to-market accounting method. Under this method, the changes in contract values are reported currently in earnings.
Oil and Gas Operations
Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.
Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants and equipment. Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for the classification of reserves as proved, the associated leasehold costs are reclassified to proved properties.
Oil and gas exploration costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field, or while we seek government or co-venture approval of development plans or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves.
Oil and gas development costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.
Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Assets are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.
When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
We record the fair value of legal obligations to retire and remove long-lived assets in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related properties, plants and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plants and equipment is depreciated over the useful life of the related asset.
45
Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable and estimable.
Results of Operations
Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012
Oil and Gas Revenue
Oil and gas revenue for the quarter ended September 30, 2013 increased by 4.5% to $17.2 million from $16.5 million in the 2012 quarter. For the nine month period ended September 30, 2013 oil and gas revenue decreased by 9.1% to $54.2 million from $59.6 million in the 2012 period.
For the quarter ended September 30, 2013, the increase in revenue was attributable to a 15.1% increase in oil revenues on a 9.2% increase in oil production volumes and a 5.4% increase in average oil prices realized partially offset by a 62.2% decline in gas revenues on a 66.3% decrease in gas production volumes partially offset by a 12.6% increase in average prices realized, each as compared to the 2012 quarter. For the nine months ended September 30, 2013, the decrease in revenue was attributable to a 6.1% decline in oil revenues on a 4.7% decrease in oil production volumes and a 1.5% decrease in average oil prices realized and a 32.0% decline in gas revenues on a 45.3% decrease in gas production volumes partially offset by a 24.2% increase in average gas prices realized, each as compared to the 2012 period.
The following table discloses the oil and gas sales revenues, net oil and natural gas production volumes and average sales prices for the three and nine months ended September 30, 2013 and 2012:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, | ||||||||||
|
| 2013 |
|
| 2012 |
|
| 2013 |
|
| 2012 | ||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
| $ | 16,345,209 |
|
| $ | 14,206,497 |
|
| $ | 49,566,017 |
|
| $ | 52,790,300 |
Gas |
|
| 850,567 |
|
|
| 2,247,628 |
|
|
| 4,619,417 |
|
|
| 6,798,143 |
Total oil and gas revenues |
| $ | 17,195,776 |
|
| $ | 16,454,125 |
|
| $ | 54,185,434 |
|
| $ | 59,588,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
| 150,543 |
|
|
| 137,913 |
|
|
| 461,066 |
|
|
| 483,808 |
Gas (Mcf) |
|
| 186,798 |
|
|
| 555,062 |
|
|
| 1,060,525 |
|
|
| 1,937,399 |
Total production (Boe) |
|
| 181,676 |
|
|
| 230,423 |
|
|
| 637,820 |
|
|
| 806,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
| $ | 108.58 |
|
| $ | 103.01 |
|
| $ | 107.51 |
|
| $ | 109.12 |
Gas (per Mcf) |
|
| 4.56 |
|
|
| 4.05 |
|
|
| 4.36 |
|
|
| 3.51 |
Total average sales price (per Boe) |
| $ | 94.65 |
|
| $ | 71.41 |
|
| $ | 84.96 |
|
| $ | 73.87 |
46
The decrease in gas production during the quarter and nine month period, outside of natural reserve declines, was primarily due to reductions in Main Pass 25, Main Pass 46, Main Pass 52, Grand Bay and Breton Sound Fields. In Main Pass 25 Field, production was curtailed due to third party handling issues and a temporary lack of available gas lift gas accounting for a decrease in production of 55.0 MMcf (or, 9.2 MBOE) compared to the 2012 nine month period . These issues were resolved during the third quarter and gas production was back to 2012 levels for the quarter. In Main Pass 46 Field, the Catina well suffered gradually worsening flow line restrictions and was shut-in for most of August 2013 for repair. As a result, gas production from Catina was down 10.2 MMcf and 46.2 MMcf (or, 1.7 MBOE and 7.7 MBOE) for the quarter and nine month period, respectively, as compared to 2012. The SL 20034 #1 well became fully depleted in the 6100’ sand resulting in a decrease of 29.7 MMcf and 184.5 MMcf (or, 5.0 and 30.8 MBOE) for the quarter and nine month period, respectively, as compared to 2012. This well was recently recompleted into a new producing zone. In Main Pass 52 Field, natural declines and depleted production zones resulted in a decrease in gas production of 53.1 MMcf and 153.5 MMcf (or, 8.9 MBOE and 25.6 MBOE) for the quarter and nine month period, respectively, as compared to 2012. In Grand Bay Field, shut-ins due to drilling of our QQ25 well, work associated with infrastructure improvements, mechanical issues, gas lift interruptions, flow line testing and repair and down time on compressors were principal drivers of a decline in gas production of 258.9 MMcf and 320.7 MMcf (or, 43.2 MBOE and 320.7 MBOE) for the quarter and nine month period, respectively, as compared to 2012. In the Breton Sound Fields, gas production is down 98.5 MMcf (or, 16.4 MBOE) for the nine month period, as compared to 2012, due to natural declines in the 2012 principal producing wells, but has increased by 33.0 MMcf (or, 5.5 MBOE) for the quarter, as compared to 2012, due to the completion of the North Tiger well in the fourth quarter of 2012.
Oil production was down 22.7 MBbl for the nine month period as compared to 2012. This decrease was primarily due to the flow line problems experienced in the Main Pass 46 Field which resulted in a decrease of 34.7 MBbl. In addition, shut-ins in the Main Pass 25 Field caused by construction projects resulted in a decrease of 26.3 MBbl for the nine month period as compared to 2012. These decreases were partially offset by the fact the North Tiger well was completed in the fourth quarter of 2012. For the quarter, oil production increased by 12.6 MBbl, as compared to 2012, primarily due to the completion of the Rocky and Zeke wells during the third quarter.
The increase in realized hydrocarbon prices reflects a general strengthening of both crude oil and natural gas prices. We continued to realize a premium pricing on both our crude oil and natural gas production.
Following quarter-end, in early October 2013, we were substantially 100% shut-in for a day as pipeline operators and other third party service providers temporarily ceased operations in the Gulf of Mexico as a precaution prior to the arrival of Tropical Storm Karen. No material damage was sustained as a result of the storm but it took five days to bring our properties back to full production. As a result, we will experience some deferral of production and associated revenues during the fourth quarter.
Other Revenues
Other revenue for the quarter ended September 30, 2013 decreased to $3,466 from $269,810 in the 2012 quarter. For the nine months ended September 30, 2013, other revenue decreased to $249,815 from $1,467,403 for the 2012 period. The decrease in other revenue was principally as a result of the one-time nature of lawsuit settlements, totaling $604,591, in the 2012 period and decreases in production handling fees and a net profits interest during the 2013 period.
Operating Expenses
Operating expenses increased by 51.7% to $19.5 million for the quarter ended September 30, 2013 from $12.9 million in the 2012 quarter. The following table sets forth the components of operating expenses for the 2013 and 2012 quarters:
| Three Months Ended |
| Three Months Ended | ||||||||
| September 30, 2013 |
| September 30, 2012 | ||||||||
| Total |
| Per Boe |
| Total |
| Per Boe | ||||
Lease operating expense | $ | 5,490,268 |
| $ | 30.22 |
| $ | 4,622,010 |
| $ | 20.06 |
Workover expense |
| 848,094 |
|
| 4.67 |
|
| 306,745 |
|
| 1.33 |
Exploration expense |
| 462,994 |
|
| 2.55 |
|
| 213,733 |
|
| 0.93 |
Loss on plugging and abandonment |
| 727,039 |
|
| 4.00 |
|
| - |
|
| - |
Depreciation, depletion and amortization |
| 4,919,418 |
|
| 27.08 |
|
| 3,658,002 |
|
| 15.87 |
Impairment expense |
| 2,179,075 |
|
| 11.99 |
|
| 44,276 |
|
| 0.19 |
Accretion expense |
| 638,097 |
|
| 3.51 |
|
| 555,504 |
|
| 2.41 |
General and administrative |
| 2,365,501 |
|
| 13.02 |
|
| 1,971,634 |
|
| 8.56 |
Severance taxes |
| 1,900,292 |
|
| 10.46 |
|
| 1,502,134 |
|
| 6.52 |
| $ | 19,530,778 |
| $ | 107.50 |
| $ | 12,874,038 |
| $ | 55.87 |
47
Operating expenses increased by 5.5% to $51.6 million for the nine months ended September 30, 2013 from $48.9 million in the 2012 period. The following table sets forth the components of operating expenses for the 2013 and 2012 periods:
| Nine Months Ended |
| Nine Months Ended | ||||||||
| September 30, 2013 |
| September 30, 2012 | ||||||||
| Total |
| Per Boe |
| Total |
| Per Boe | ||||
Lease operating expense | $ | 15,293,422 |
| $ | 23.97 |
| $ | 13,860,709 |
| $ | 17.18 |
Workover expense |
| 2,277,226 |
|
| 3.57 |
|
| 3,846,046 |
|
| 4.77 |
Exploration expense |
| 746,965 |
|
| 1.17 |
|
| 369,419 |
|
| 0.46 |
Loss on plugging and abandonment |
| 727,039 |
|
| 1.14 |
|
| 2,468,969 |
|
| 3.06 |
Dry hole costs |
| - |
|
| - |
|
| 93,353 |
|
| 0.11 |
Depreciation, depletion and amortization |
| 15,790,454 |
|
| 24.76 |
|
| 14,170,532 |
|
| 17.57 |
Impairment expense |
| 2,179,075 |
|
| 3.42 |
|
| 44,276 |
|
| 0.05 |
Accretion expense |
| 1,914,291 |
|
| 3.00 |
|
| 1,666,512 |
|
| 2.07 |
General and administrative |
| 6,804,243 |
|
| 10.67 |
|
| 7,042,299 |
|
| 8.73 |
Severance taxes |
| 5,892,904 |
|
| 9.24 |
|
| 5,375,259 |
|
| 6.66 |
| $ | 51,625,619 |
| $ | 80.94 |
| $ | 48,937,374 |
| $ | 60.66 |
The changes in operating expenses were primarily attributable to the factors discussed below.
Lease Operating Expense
Lease operating expenses for the quarter ended September 30, 2013 increased 18.9% to $5.5 million from $4.6 million in the 2012 quarter and, on a per BOE basis, increased 50.6% to $30.22 per BOE from $20.06 per BOE, in the 2012 quarter. Lease operating expenses for the nine months ended September 30, 2013 increased 10.4% to $15.3 million from $13.9 million in the 2012 period and on a per BOE basis, increased 39.6% to $23.97 per BOE from $17.18 per BOE in the 2012 period. The increase in lease operating expense for the three and nine month periods was primarily due to the nonrecurring cost of a barge removal in the Little Bay Field totaling $0.4 million and the cost of chemically treating and cleaning our sales lines and flow lines totaling $0.6 million.
Operating costs in our fields have historically been relatively high due to water handling, the need for gas lift to maintain oil production and due to the need for marine transportation in the shallow water, bay environment. The increase in lease operating expenses on a per BOE basis for the quarter and nine month period was primarily attributable to the decreases in production volumes and the fixed nature of certain lease operating expenses.
Workover Expense
Workover expense for the quarter ended September 30, 2013 increased to $848,094 from $306,745 in the 2012 quarter and decreased to $2,277,226 from $3,846,046 for the nine months ended September 30, 2013 from the 2012 period. The change in workover expense was attributable to variances in the number of workovers undertaken during the respective periods.
Exploration Expense
Exploration expense for the quarter ended September 30, 2013 increased to $462,994 from $213,733 in the 2012 quarter. Exploration expense for the nine months ended September 30, 2013 increased to $746,965 from $369,419 in the 2012 period. The increase in exploration expenses principally relate to increased delay rentals and filed studies, including $138,698 relating to our Gulf of Mexico shelf acreage incurred during the 2013 quarter, and increased investment in field studies related to Grand Bay Field, in particular seismic attribute and AVO analysis relating to the Grand Bay deep prospects.
Loss on plugging and abandonment
Loss on plugging and abandonment for the quarter and nine months ended September 30, 2013 totaled $727,039 due to cost of plugging and abandoning a well in Vermilion Bay 16 field that exceeded those estimated in our calculation of asset retirement obligation liabilities. This well was a high pressure well which we discovered had been completed with a kill string resulting in the need for additional plugs and tubing cuts. Accordingly, the actual costs incurred in plugging and abandoning this well was substantially higher than we estimated and would expect to incur in future plugging operations.
48
Loss on plugging and abandonment for the nine months ended September 30, 2012 totaled $2,468,969 due to costs of plugging and abandoning wells in Little Bay, South Atchafalaya Bay and Crooked Bayou fields that exceeded those estimated in our calculation of asset retirement obligation liabilities. Four of the wells plugged were the deepest and highest pressure wells in our entire inventory of wells to be plugged. These wells were orphaned wells on expired leases which we inherited from the previous owners and which have never produced since we have owned the assets. In addition, several of the wells had unanticipated severe casing damage. Accordingly, the actual costs incurred in plugging and abandoning these wells was substantially higher than we estimated and would expect to incur in future plugging operations.
Depreciation, Depletion and Amortization (DD&A)
Depreciation, depletion and amortization for the quarter ended September 30, 2013 increased 34.5% to $4,919,418 from $3,658,002 in the 2012 quarter and increased to $27.08 per BOE from $15.87 per BOE in the 2012 quarter. Depreciation, depletion and amortization for the nine months ended September 30, 2013 increased 11.4% to $15,790,454 from $14,170,532 in the 2012 period and increased to $24.76 per BOE from $17.57 per BOE in the 2012 period.
We utilize the successful efforts method of accounting for oil and gas producing activities. Under this method, DD&A is computed on the units-of-production method separately on each individual property and includes the accrual of future plugging and abandonment costs.
The increase in DD&A expense and DD&A expense per BOE, during the 2013 periods was attributable to additional capital expenditures incurred in our development program during 2013 and relating to work in progress at the end of 2012 that was placed in service during 2013.
Impairment Expense
Impairment expense of $2,179,075 was recorded during the 2013 quarter due to the loss of the lease at our Little Bay Field when production levels fell below commercial levels.
Impairment expense relating to our Breton Sound 51 Field of $44,276 was recorded during the 2012 quarter. The impairment expense was a result of one of the three producing wells in the filed becoming fully depleted during the quarter.
Accretion expense
Accretion expense relating to our asset retirement obligations increased to $638,097 from $555,504 for the quarter ended September 30, 2013 as compared to the 2012 quarter. Accretion expense relating to our asset retirement obligations increased to $1,914,291 from $1,666,512 for the nine months ended September 30, 2013 as compared to the 2012 period.
The increase in accretion expense was attributable to changes in the anticipated plugging dates and discount rates used in calculating the asset retirement obligation for certain fields.
General and Administrative
General and administrative (“G&A”) expense for the quarter ended September 30, 2013 increased 20.0% to $2,365,501 as compared to $1,971,634 in the 2012 quarter, and increased 52.1% to $13.02 from $8.56 on a per BOE basis. For the nine months ended September 30, 2013, G&A expense decreased by 3.4% to $6,804,243 from $7,042,299 in the 2012 period. The increase in G&A expense for the quarter was primarily due to consulting fees relating to reservoir engineering and an increase in the employee headcount resulting in higher salaries and benefits. The decrease in G&A expense for the nine month period was primarily attributable to a temporary decrease in head count during the first and portions of the second quarter of 2013 and reductions in employee stock compensation and the year-end bonus accrual which were partially offset by the increase in reservoir consulting costs.
Severance Taxes
Severance taxes for the quarter ended September 30, 2013 increased to $1,900,292 from $1,502,134 in the 2012 quarter. For the nine months ended September 30, 2013, severance taxes increased to $5,892,904 from $5,375,259 for the 2012 period. The increase was primarily attributable a reduced number of inactive wells eligible for certain Louisiana severance tax exemptions, partially offset by reduced revenues.
49
Other Income (Expense), Net
Net other expense increased to $5.4 million in for the quarter ended September 30, 2013 from $4.3 million for the 2012 quarter. For the nine months ended September 30, 2013, other expense increased to $15.9 million from $13.0 million in the 2012 period.
Interest expense reflects interest incurred on debt under our senior secured notes. The increase in interest expense was attributable to our placement of an additional $25.0 million in principal amount of senior secured notes in December 2012.
Income Tax Benefit
For the quarter ended September 30, 2013 we recorded an income tax benefit of $2,683,382 compared to $48,062 during the 2012 quarter. For the nine months ended September 30, 2013 we recorded an income tax benefit of $4,196,914 compared to $213,896 in the 2012 period.
Our effective tax rates were different than our federal statutory tax rate due to Louisiana state income taxes associated with income from various locations in which we have operations. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, the timing, amount, and location of future production and future operating expenses and capital costs.
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Oil and Gas Revenue
Oil and gas revenue for the year ended 2012 increased by 8% to $82.5 million from $76.2 million in 2011.
The increase in revenue was attributable to an 18% increase in production volumes partially offset by an 8% decline in average hydrocarbon prices realized during 2012. The following table discloses the oil and gas sales revenues, net oil and natural gas production volumes, and average sales prices for the years ended December 31, 2012 and 2011:
| 2012 |
| 2011 | ||
Revenues |
|
|
|
|
|
Oil | $ | 72,959,377 |
| $ | 65,649,756 |
Gas |
| 9,569,555 |
|
| 10,509,512 |
Total oil and gas revenues | $ | 82,528,932 |
| $ | 76,159,268 |
|
|
|
|
|
|
Production |
|
|
|
|
|
Oil (Bbls) |
| 676,400 |
|
| 605,900 |
Gas (Mcf) |
| 2,639,500 |
|
| 2,038,000 |
Total production (Boe) |
| 1,116,317 |
|
| 945,567 |
|
|
|
|
|
|
Average sales price |
|
|
|
|
|
Oil (per Bbl) | $ | 107.86 |
| $ | 108.35 |
Gas (per Mcf) |
| 3.63 |
|
| 5.16 |
Total average sales price (per Boe) | $ | 73.93 |
| $ | 80.54 |
The increase in production volumes during 2012 was attributable to increased investment in, and acceleration of, our drilling, recompletion and workover program and investments in infrastructure projects to eliminate bottlenecking and infrastructure related constraints on production. Beginning in the second quarter of 2011 and continuing through 2012, we have substantially increased our investment in our drilling and development program, with investments totaling $56.3 million in 2012 as compared to $20.3 million in 2011 up from $7.7 million in 2010. The gains in production volumes attributable to increased investment in our drilling and development program, and infrastructure projects, was partially offset during 2012 by the shut-in of production attributable to Hurricane Isaac and the following transition period to ramp production up to pre-hurricane levels.
50
The decrease in average prices realized from the sale of oil and gas reflected continued weakening of natural gas prices during much of 2012 combined with slightly weaker prices realized from crude oil sales. Our crude oil prices realized reflect a premium to prevailing WTI prices as a result of the quality of our LLS and HLS oil production. Prior to our reinstitution of a hedging program during the third quarter of 2012, we were fully unhedged and benefited from favorable crude oil pricing while also being exposed to declining natural gas prices. With the institution of our hedging program late in the third quarter, approximately 22% of our crude oil production volume during 2012 was sold under hedging arrangements. None of our natural gas production was sold under hedging arrangements during 2012
Other Revenues
Other revenues consist principally of (i) a net profits interest attributable to operating the Breton Sound 31 field, for which we receive a percentage of profits, (ii) production handling fees from our Vermilion 16 field, (iii) during 2012, settlements of lawsuits against the former owners of The Harvest Group LLC and Harvest Oil & Gas, LLC and (iv) during 2011, refunds of severance taxes under a Louisiana incentive program relating to previously inactive wells. For 2012, other revenues decreased to $1.4 million from $4.8 million in 2011. The decrease in other revenue was principally attributable to the one-time nature of the severance tax refunds totaling $2.6 million during 2011.
Operating Expenses
Operating expenses increased by 28.8% to $71.7 million for 2012 from $55.7 million in 2011. The following table sets forth the components of operating expenses, in total and on a per Boe basis, for 2012 and 2011:
| 2012 |
| 2011 | ||||||||
| Total |
| Per Boe |
| Total |
| Per Boe | ||||
Lease operating expense | $ | 19,317,283 |
| $ | 17.30 |
| $ | 17,123,890 |
| $ | 18.11 |
Workover expense |
| 3,828,197 |
|
| 3.43 |
|
| 2,666,600 |
|
| 2.82 |
Exploration expense |
| 547,192 |
|
| 0.49 |
|
| 596,065 |
|
| 0.63 |
Loss on plugging and abandonment |
| 2,468,969 |
|
| 2.21 |
|
| 393,599 |
|
| 0.42 |
Dry hole costs |
| 93,353 |
|
| 0.08 |
|
| 3,912,823 |
|
| 4.14 |
Depreciation, depletion and amortization |
| 27,407,700 |
|
| 24.55 |
|
| 15,591,048 |
|
| 16.49 |
Impairment expense |
| 401,752 |
|
| 0.36 |
|
| 641,791 |
|
| 0.68 |
Accretion expense |
| 1,510,165 |
|
| 1.35 |
|
| 1,672,900 |
|
| 1.77 |
Gain on revision of asset retirement obligations |
| (245,007) |
|
| (0.22) |
|
| (303,633) |
|
| (0.32) |
Gain on purchase price adjustment |
| - |
|
| - |
|
| (1,426,778) |
|
| (1.51) |
General and administrative expenses |
| 8,584,486 |
|
| 7.69 |
|
| 8,704,536 |
|
| 9.21 |
Severance taxes |
| 7,768,426 |
|
| 6.96 |
|
| 6,090,666 |
|
| 6.44 |
| $ | 71,682,516 |
| $ | 64.21 |
| $ | 55,663,507 |
| $ | 58.88 |
The changes in operating expenses were primarily attributable to the factors discussed below.
Lease Operating Expense
Lease operating expenses for 2012 increased 12.8% to $19.3 million from $17.1 million in 2011, but on a per BOE basis decreased 4.4% to $17.31 per BOE from $18.11 per BOE in 2011.
Operating costs in our fields have historically been relatively high due to water handling, the need for gas lift to maintain oil production and due to the need for marine transportation in the shallow water, bay environment. The increases in operating expenses during 2012 were primarily attributable to an increase in production volumes and an increase in operating expenses on third party operated properties and increases in transportation expenses. The increase in lease operating expense on a per BOE basis was primarily attributable to the fixed nature of certain lease operating expenses combined with the losses of production attributable to Hurricane Isaac.
Workover Expense
Workover expense for 2012 increased 43.6% to $3.8 million from $2.7 million in 2011. The increase in workover expense was attributable to an increase in the number of workovers completed in 2012.
51
Exploration Expense
Exploration expense for 2012 decreased 8.2% to $0.5 million from $0.6 million in 2011. Exploration expenses during 2012 and 2011 principally relate to delay rental payments.
Loss on plugging and abandonment
Loss on plugging and abandonment increased to $2.5 million in 2012 from $0.4 million in 2011. The loss in each year reflects plugging and abandonment costs in excess of estimated costs reflected in our asset retirement obligation liabilities. The increase in loss reflected our determination to plug orphaned wells on expired leases in Little Bay, South Atchafalaya Bay and Crooked Bay which we inherited from the previous owners and have never produced since we have owned the assets. Four of the wells plugged were the deepest and highest pressure wells in our inventory of wells to be plugged. In addition several of the wells had unanticipated severe casing damage. Accordingly, the actual costs incurred in plugging and abandoning these wells was substantially higher than we estimated and would expect to incur in future plugging operations.
Dry Hole Costs
Dry hole costs decreased to $0.1 million in 2012 from $3.9 million in 2011. The decrease in dry hole costs reflects the cost of the Rio Grande well which was drilled as a dry hole during 2011.
Depreciation, Depletion and Amortization (DD&A)
Depreciation, depletion and amortization for 2012 increased 75.8% to $27.4 million from $15.6 million in 2011. The increase in DD&A was attributable to increased production, added capital expenditures and a reduction in natural gas reserves associated with certain properties, most notably the Mesa Verde well, where sands were thinner than anticipated, and Little Bay, where increased capital costs in our reserve report resulted in a reduction in reserves. DD&A is computed on the units-of-production method separately on each individual property and includes the accrual of future plugging and abandonment costs.
Impairment expense
Impairment expense for 2012 decreased 37.4% to $0.4 million from $0.6 million in 2011. Impairment expense during 2012 related to our Breton Sound 51 Field and was a result of one of the three producing wells in the field becoming fully depleted during the year. Impairment expense during 2011 related to one property on which development costs and carrying value, combined, were determined to exceed fair value.
Accretion expense
Accretion expense for 2012 decreased 9.7% to $1.5 million from $1.7 million in 2011. Accretion expense relates to our asset retirement obligations. The decrease in accretion expense was attributable to changes in the anticipated plugging dates and discount rates used in calculating the asset retirement obligation for certain fields.
Gain on revision of asset retirement obligations
Gain on revision of asset retirement obligations was $0.2 million in 2012 as compared to $0.3 million in 2011. These gains are due primarily to downward revisions in the asset retirement obligations relating to two properties which exceeded the carrying amount of the property
Gain on purchase price adjustment
Gain on purchase price adjustment was $0 in 2012 and $1.4 million in 2011. Gain on purchase price adjustment arose from adjustments to the original purchase price of certain of our assets, relating to site specific trust accounts, which occurred longer than one year after the acquisition date.
52
General and Administrative Expense
General and administrative expense for 2012 decreased 1% to $8.6 million from $8.7 million in 2011, and decreased 16.5% on a per BOE basis. The decrease in general and administrative expense was primarily attributable to reduced personnel costs and reduced legal expenses
Severance Taxes
Severance taxes for 2012 increased 27.5% to $7.8 million from $6.1 million in 2011 and increased 8.1% from $6.44 per BOE in 2011 to $6.96 per BOE in 2012. The increase was primarily due to increased production and by a decrease in the number of inactive wells eligible for certain Louisiana severance tax exemptions.
Other Income (Expense), Net
Net other expenses totaled $17.6 million for 2012 as compared $10.8 million for 2011. The following table sets forth the components of net other income (expenses) for 2012 and 2011:
| 2012 |
| 2011 | ||
Financing expense |
| (7,527) |
|
| (837,364) |
Gain on extinguishment of debt |
| — |
|
| 7,708,486 |
Interest expense (net) |
| (17,619,063) |
|
| (17,698,849) |
| $ | (17,626,590) |
| $ | (10,827,727) |
Financing Expense. Financing expense totaled $0.8 million during 2011 and consisted of commitment fees and costs associated with the planned establishment of a revolving credit facility during 2011. We opted to seek more favorable credit terms in lieu of closing the revolving credit facility resulting in our expensing all costs associated with efforts to establish the facility.
Gain on Extinguishment of Debt. Gain on extinguishment of debt totaled $7.7 million during 2011. The gain on extinguishment of debt relates to the 2011 retirement of indebtedness under our prior credit facilities and reflects the fair market value of the warrants cancelled on retirement of that debt net of unamortized debt issuance costs and debt discount.
Interest Expense, Net. Interest expense, net, for 2012 remained virtually unchanged at $17.6 million as compared to $17.7 million in 2011. Interest expense, net reflects interest incurred on debt under our senior secured notes and our prior term credit agreement and revolving credit agreement, partially offset by interest earned on cash balances held. The decrease in net interest expense was attributable to a reduction in our average outstanding indebtedness. With our placement of an additional $25.0 million in principal amount of senior secured notes in December 2012, our interest expense is expected to increase during 2013.
Reorganization Expenses
Reorganization expenses reflect payments to professionals and other fees incurred in connection with our prior Chapter 11 case. Reorganization expenses decreased to $0.2 million in 2012 from $0.4 million in 2011 due to our exit from bankruptcy in May 2010.
Income Tax Provision (Benefit)
For 2012, we recorded income tax benefit of $1.8 million compared to $6.8 million during 2011. The income tax benefit during 2012 and 2011 primarily reflects recognition of a deferred tax asset relating to our net operating loss carryforwards.
Our effective tax rates for 2012 and 2011 were 32.1% and (49.1)%, respectively. Our effective tax rates were different than our federal statutory tax rate due to state income taxes associated with income from various locations in which we have operations. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, the timing, amount, and location of future production and future operating expenses and capital costs.
53
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
We operated as debtors-in-possession under Chapter 11 of the U.S. Bankruptcy Code from March 31, 2009 until our exit from bankruptcy on May 14, 2010. During that period, and continuing through completion of our capital raising efforts in mid-2011, our operations, and operating results, were significantly affected by, among other things, our incurrence of substantial expenses directly and indirectly related to our bankruptcy and the curtailment or delay of investments in our development program and normal field maintenance operations arising from the cumbersome and slow process of obtaining various approvals required for use of cash and our inability to draw on our revolving credit facility.
Oil and Gas Revenue
Oil and gas revenue for the year ended 2011 increased by 44.6% to $76.2 million from $52.7 million in 2010.
The increase in revenue was attributable to a 31.9% increase in average hydrocarbon prices realized during 2011 and a 9.5% increase in production volumes. The following table discloses the oil and gas sales revenues, net oil and natural gas production volumes, and average sales prices for the years ended December 31, 2011 and 2010:
| 2011 |
| 2010 | ||
Revenues |
|
|
|
|
|
Oil | $ | 65,649,756 |
| $ | 44,141,235 |
Gas |
| 10,509,512 |
|
| 8,592,972 |
Total oil and gas revenues | $ | 76,159,268 |
| $ | 52,734,207 |
|
|
|
|
|
|
Production |
|
|
|
|
|
Oil (Bbls) |
| 605,900 |
|
| 550,000 |
Gas (Mcf) |
| 2,038,000 |
|
| 1,882,800 |
Total production (Boe) |
| 945,567 |
|
| 863,800 |
|
|
|
|
|
|
Average sales price |
|
|
|
|
|
Oil (per Bbl) | $ | 108.35 |
| $ | 80.26 |
Gas (per Mcf) |
| 5.16 |
|
| 4.56 |
Total average sales price (per Boe) | $ | 80.54 |
| $ | 61.05 |
The increase in production during 2011 was attributable to our recompletion and workover program, drilling of our Catina and Roux wells and efforts during 2011 to address deferred maintenance and third party facilities capacity limitations that resulted in the resumption of production or increase in production from shut-in wells and wells producing below capacity. The increase in production during 2011 reflects additional investment in, and acceleration of, our development and drilling plan commencing in the second quarter of 2011 which, in turn, reflected our strengthened cash position attributable to capital raising efforts and improved operating cash flows. Investments in our drilling and development program totaled $20.3 million in 2011 as compared to $7.7 million in 2010.
The increase in average prices realized from the sale of oil and gas reflected a sharp rise in global commodity prices, in particular crude oil prices, beginning in late 2010 and continuing through 2011. Our increase in average prices realized also reflects a premium to prevailing WTI prices as a result of the quality of our LLS and HLS oil production. At December 31, 2011, we were fully unhedged and, during 2011, benefited from rising oil prices and premiums to prevailing WTI prices while also being exposed to declining natural gas prices.
Other Revenues
Other revenues consist principally of (i) a net profits interest attributable to operating the Breton Sound 31 field, for which we receive a percentage of profits, (ii) production handling fees from our Vermilion 16 field, (iii) in 2010, proceeds from the sale of our Adcock Farms lease and well, and (iv) in 2011, refunds of severance taxes under a Louisiana incentive program relating to previously inactive wells. For 2011, other revenues increased to $6.2 million from $2.3 million in 2010. The increase in other revenues was principally attributable to severance tax refunds of $2.6 million received during 2011.
54
Operating Expenses
Operating expenses increased by 10.9% to $55.7 million for 2011 from $50.2 million in 2010. The following table sets forth the components of operating expenses, in total and on a per Boe basis, for 2011 and 2010:
| 2011 |
| 2010 | ||||||||
| Total |
| Per Boe |
| Total |
| Per Boe | ||||
Lease operating expense | $ | 17,123,890 |
| $ | 18.11 |
| $ | 13,774,406 |
| $ | 15.95 |
Workover expense |
| 2,666,600 |
|
| 2.82 |
|
| 2,154,482 |
|
| 2.49 |
Exploration expense |
| 596,065 |
|
| 0.63 |
|
| 1,921,943 |
|
| 2.22 |
Loss on plugging and abandonment |
| 393,599 |
|
| 0.42 |
|
| - |
|
| - |
Dry hole costs |
| 3,912,823 |
|
| 4.14 |
|
| - |
|
| - |
Depreciation, depletion and amortization |
| 15,591,048 |
|
| 16.49 |
|
| 16,001,826 |
|
| 18.52 |
Impairment expense |
| 641,791 |
|
| 0.68 |
|
| - |
|
| - |
Accretion expense |
| 1,672,900 |
|
| 1.77 |
|
| 1,668,268 |
|
| 1.93 |
Gain on revision of asset retirement obligations |
| (303,633) |
|
| (0.32) |
|
| - |
|
| - |
Gain on purchase price adjustment |
| (1,426,778) |
|
| (1.51) |
|
| - |
|
| - |
Loss on settlement of accounts payable |
| - |
|
| - |
|
| 990,786 |
|
| 1.15 |
General and administrative expenses |
| 8,704,536 |
|
| 9.21 |
|
| 8,476,124 |
|
| 9.81 |
Severance taxes |
| 6,090,666 |
|
| 6.44 |
|
| 5,214,677 |
|
| 6.04 |
| $ | 55,663,507 |
| $ | 58.88 |
| $ | 50,202,512 |
| $ | 58.11 |
As more fully described below, the change in operating expenses was primarily attributable to increased lease operating expense, workover expense, loss on plugging and abandonment, dry hole costs and production and severance taxes, partially offset by decreased exploration expense.
Lease Operating Expenses
Lease operating expenses for 2011 increased 24.3% to $17.1 million, or $18.11 per Boe, from $13.8 million, or $15.95 per Boe, in 2010.
Operating costs in our fields have historically been relatively high due to water handling, the need for gas lift to maintain oil production and due to the need for marine transportation in the shallow water, bay environment. We have been actively engaged in field management efforts to reduce our lease operating expenses. The increase in lease operating expenses during 2011 was primarily attributable to increases in equipment rental, transportation expense and field personnel.
Workover Expense
Workover expense for 2011 increased 23.8% to $2.7 million from $2.2 million in 2010. The increase in workover expense was attributable to more workover activity in 2011.
Exploration Expense
Exploration expense for 2011 decreased 69.0% to $0.6 million from $1.9 million in 2010. The decrease in exploration expense was attributable to the completion of our full field study program in early 2011 and the 2010 purchase of a seismic data license ($0.7 million).
Loss on plugging and abandonment
Loss on plugging and abandonment was $0.4 million in 2011 due to the cost of plugging and abandoning wells in the Breton Sound 51 field that exceeded those estimated in our calculation of asset retirement obligation liabilities
55
Depreciation, Depletion, Amortization and Impairment (DD&A)
Depreciation, depletion and amortization for 2011 decreased 2.6% to $15.6 million from $16.0 million in 2010. Changes in DD&A were attributable to different production rates and added capital expenditures. DD&A is computed on the units-of-production method separately on each individual property and includes the accrual of future plugging and abandonment costs. During the year ended December 31, 2011, Saratoga recorded an impairment expense of $0.6 million relating to one property when development costs incurred during the year combined with the existing carrying value exceeded the fair value.
Accretion expense
Accretion expense for 2011 remained unchanged from 2010 at $1.7 million.
Gain on revision of asset retirement obligation
Gain on revision of asset retirement obligation was $0.3 million due to downward revisions in the asset retirement obligations relating to one property which exceeded the carrying amount of the property
Gain on purchase price adjustment
Gain on purchase price adjustment was $1.4 million due to adjustments to the original purchase price of certain of Saratoga’s assets, relating to site specific trust accounts, which occurred longer than one year after the acquisition date.
Loss on settlement of accounts payable
Loss on settlement of accounts payable reflects the fair value of the common stock issued, on a one-time basis, to our vendors during 2010 as part of the settlement terms in our plan of reorganization.
General and Administrative Expenses and Other
General and administrative expense for 2011 increased 2.7% to $8.7 million from $8.5 million in 2010. The increase in general and administrative expense was attributable to increased compensation expense ($2.6 million) relating to salary increases, additional head count and cash bonuses partially offset by a decrease in stock-based compensation. The change in stock-based compensation was attributable to broad based stock option grants with immediate vesting during 2010 in connection with our exit from bankruptcy. Non-cash G&A expense, associated principally with stock-based compensation, totaled $0.9 million and $2.6 million in 2011 and 2010, respectively.
Severance Taxes
Severance taxes for 2011 increased 16.8% to $6.1 million from $5.2 million in 2010. The increase was primarily due to increased production and prices partially offset by decreased severance tax rates for our natural gas production that began in July 2010 and severance tax incentives relating to previously inactive wells.
Other Income (Expense), Net
Net other expenses totaled $10.8 million for 2011 as compared $21.8 million for 2010. The following table sets forth the components of net other income (expenses) for 2011 and 2010:
| 2011 |
| 2010 | ||
Commodity derivative income (expense) | $ | — |
| $ | 696,550 |
Financing expense |
| (837,364) |
|
| — |
Gain on extinguishment of debt |
| 7,708,486 |
|
| — |
Interest expense (net) |
| (17,698,849) |
|
| (22,469,584) |
| $ | (10,827,727) |
| $ | (21,773,034) |
As more fully described below, the changes in other income (expense), net, were principally attributable to the gain realized in the 2011 on the extinguishment of debt, liquidation of our commodity derivates during 2010, resulting in a gain for 2010 compared to no income or expense from commodity derivatives during 2011, financing expenses incurred during 2011 relating to a revolving credit facility and a decrease in interest expense reflecting a lower average interest rate on borrowed funds.
56
Commodity Derivative Income (Expense). Commodity derivative income decreased to $0 during 2011 from $0.7 million during 2010. The commodity derivative income recognized during 2010 related to the liquidation of our commodity derivatives during 2010. We had no commodity derivative activities during 2011.
Financing Expense. Financing expense consists of commitment fees and costs associated with the planned establishment of a revolving credit facility during 2011. We opted to seek more favorable credit terms in lieu of closing the revolving credit facility resulting in our expensing all costs associated with efforts to establish the facility.
Gain on Extinguishment of Debt. Gain on extinguishment of debt totaled $7.7 million during 2011. The gain on extinguishment of debt relates to the 2011 retirement of indebtedness under our prior credit facilities and reflects the fair market value of the warrants cancelled on retirement of that debt net of unamortized debt issuance costs and debt discount.
Interest Expense, Net. Interest expense, net, reflects interest incurred on debt under our term credit agreement and revolving credit agreement which were retired in July 2011 and our new senior secured notes which were issued in July 2011, partially offset by interest earned on cash balances held. Net interest expense decreased to $17.7 million in 2011 from $22.5 million in 2010. The decrease in net interest expense was attributable to a May 2010 decrease in our stated interest rate on our Amended and Restated Term Credit Agreement from 20% to 11.25% and, to a lesser extent, an increase in interest income resulting from an increase in our cash balances partially offset by an increase in the stated interest rate of our senior secured notes to 12.5% commencing in July 2011.
Reorganization Expenses
Reorganization expenses reflect payments to professionals and other fees incurred in connection with our Chapter 11 case. Reorganization expenses decreased to $0.4 million in 2011 from $2.2 million in 2010 due to our exit from bankruptcy in May 2010.
Income Tax Provision
For 2011, we recorded an income tax benefit of $6.8 million compared to income tax expense of $0.3 million for 2010. The income tax expense for 2010 was attributable to Louisiana state franchise taxes. For 2011, we recognized a deferred tax asset relating to our net operating loss carryforwards.
Our effective tax rates for 2011 and 2010 were (49.1)% and (1.5)%, respectively. Our effective tax rates were different than our federal statutory tax rate due to state income taxes associated with income from various locations in which we have operations. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, the timing, amount, and location of future production and future operating expenses and capital costs.
Financial Condition
Liquidity and Capital Resources
Our principal requirements for capital are to fund our day-to-day operations and exploration, development and acquisition activities and to satisfy our contractual obligations, primarily for the payment of interest and repayment of debt.
Since 2009, we have funded operations, including all development and related activities, out of operating cash flow and cash on hand, which funds have been supplemented by our receipt of funds from our April and July 2011 and May 2012 equity capital raises and our December 2012 and November 2013 issuances of secured notes described herein.
57
We developed, and beginning in 2011 commenced, a layered, multi-faceted development and maintenance program designed to achieve short-, mid- and long-term objectives. Short-term objectives are focused on restoration of shut-in and curtailed production through investments in infrastructure and deferred maintenance and recompletions, workovers and thru-tubing plugbacks each designed to increase or restore production volumes from wells producing below capacity and an inventory of proved developed nonproducing opportunities. Mid-term, following or in conjunction with execution of short-term opportunities, our focus is on the development of an inventory of proved undeveloped opportunities within our inventory of proved undeveloped wells targeting normally pressured oil and gas. Long-term, following or in conjunction with the execution of our short- and mid-term opportunities, our focus is on continuing development of our reserves and exploratory drilling of deep shelf opportunities. During 2011, we achieved our principal short-term objectives through substantial investments in infrastructure upgrades. During 2012 and continuing through the third quarter of 2013, while continuing to advance short-term objectives associated with continual investment in our infrastructure, recompletions and workovers, we focused on our mid-term objectives as reflected in continued investment in our developmental drilling program.
As noted, we have supplemented our cash and liquidity position through a series of equity capital raises during 2011 and 2012, consisting of (1) the receipt of $7.4 million from the sale of common stock and warrants in April 2011, (2) the receipt of $27.3 million from the sale of common stock in July 2011, and (3) the receipt of $18.4 million from the sale of common stock in May 2012. We have utilized the proceeds from the offerings of such stock and warrants to support accelerated investments in our development and maintenance program.
Further, during July 2011, we received $120.9 million of net proceeds from the sale of our Second Lien Notes and, during December 2012, we received $23.4 million of net proceeds from the sale of additional Second Notes. Funds received from the July 2011 common stock offering and offering of Second Lien Notes were used to repay indebtedness under our prior credit facilities. In November 2013, we received $25.4 million of net proceeds from the sale of our First Lien Notes.
We believe that our cash on hand at September 30, 2013, together with anticipated operating cash flow, would support current operations over the next twelve months, but not support development operations at 2013 levels. Our receipt of funding from our November 2013 First Lien Note offering will supplement our ability to fund development operations. Contingent upon operating results, we may need to secure additional financing to support development activities at 2013 levels or to curtail development activities to levels supported by operating cash flow. Our development of proved undeveloped opportunities is scalable. Depending upon the results of our short-term development initiatives, ongoing development efforts relating to our proved undeveloped opportunities and any further capital commitments, we may accelerate our planned development of proved undeveloped opportunities or otherwise adjust the nature or rate of our development program. Pursuit of our long-term plans for exploratory drilling of deep shelf prospects is expected to require funding in excess of our current resources and projected operating cash flow and to be dependent upon results attained by other operators that are currently pioneering ultra-deep drilling in the trend within which our ultra-deep prospects are located. At September 30, 2013, we were continuing to monitor developments within the ultra-deep trend and to be engaged in discussions with various potential partners relative to the potential exploration of our ultra-deep prospects. We presently lack the financial resources to carry our proportionate share of the anticipated exploration and development costs associated with such joint venture and will be required to secure additional financing to support our share of such costs and maintain our interest in such ultra-deep prospects. To that end, we expect to seek partners to enter into arrangements that will provide the necessary funding to pay some, or all, of our share of the joint venture costs with the effect of reducing our interest in the joint venture. We presently have no commitments from potential joint venture partners or to provide funding to cover our share of such costs.
We plan to seek joint venture partners for our shallow Gulf of Mexico properties, which have a primary lease term of five years and are exploratory in nature.
Unexpected declines in commodity prices or production levels, or failures in achieving production increases through short- and mid-term development plans, could result in our inability to support our operations and drilling and development plans.
Cash, Cash Flows and Working Capital
We had a cash balance of $9.6 million and a working capital deficit of $0.1 million at September 30, 2013 as compared to a cash balance of $32.3 million and working capital of $21.2 million at December 31, 2012. The decrease in cash on hand was primarily attributable to reductions in operating cash flow and investments in our development program, including lease bonus and first year rentals on our new Gulf of Mexico leases. The decrease in our working capital was primarily attributable to utilization of cash to fund our development program and Gulf of Mexico lease acquisition.
58
Operations provided cash flow of $3.5 million for the nine months ended September 30, 2013 as compared to providing $15.7 million for the nine months ended September 30, 2012. The change in operating cash flows during 2013 was principally attributable to reduced profitability resulting from lower production volumes and changes in our operating assets and liabilities.
Investing activities used cash totaling $25.2 million during the nine months ended September 30, 2013, including $1.5 million of cash used to pay lease bonuses, first year rentals and a prospect fee relating to our new Gulf of Mexico leases, as compared to cash used in investing of $45.3 million during the nine months ended September 30, 2012. We incurred $28.6 million and $54.0 million for oil and gas development activities for the nine months ended September 30, 2013 and 2012, respectively.
Financing activities used cash flows of $1.0 million during the nine months ended September 30, 2013 as compared to $22.1 million provided during the nine months ended September 30, 2012. Cash flows provided by financing activities during the 2012 period primarily related to an equity offering and funds received for the exercise of common stock options and warrants.
Debt and Non-Current Liabilities
At September 30, 2013, we had $150.8 million of indebtedness outstanding (reflecting a $1.7 million debt discount) compared to $150.4 million of indebtedness outstanding at December 31, 2012 (reflecting a $2.1 million debt discount), consisting of $152.5 million under our Second Lien Notes.
Subsequent to September 30, 2013, we issued $54.6 million in principal amount of First Lien Notes and retired $27.3 million of Second Lien Notes.
Capital Expenditures and Commitments
Our capital spending for the nine months ended September 30, 2013 was $28.6 million relating primarily to development of our oil and gas properties ($17.4 million), acquisition of Gulf of Mexico Shelf acreage ($1.4 million), 18 recompletions ($4.9 million) and investments in multiple infrastructure projects ($4.9 million).
As noted, we have the operational flexibility to react quickly with our capital expenditures to changes in our cash flows from operations. Actual levels of capital expenditures in any year may vary significantly due to many factors, including the extent to which properties are acquired, drilling results, oil and gas prices, industry conditions and the prices and availability of goods and services.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements or guarantees of third party obligations at September 30, 2013.
Inflation
We believe that inflation has not had a significant impact on our operations since inception.
59
BUSINESS
General
We are an independent oil and natural gas company engaged in the production, development, acquisition and exploitation of crude oil and natural gas properties. As of December 31, 2013, our properties consisted of 52,012 acres under lease, including 32,198 acres gross/net located in the transitional coastline in protected in-bay environments on parish and state leases in south Louisiana and 19,814 acres gross/net under federal leases in the shallow Gulf of Mexico shelf.
Our state and parish leases span 12 fields which are characterized by over 30 years of development drilling and production history, including Grand Bay field which has over 70 years of production history and over 258 MMBoe produced to date, yet remains virtually unexplored at depths greater than 15,000 feet. Substantially all of our state and parish leases are held by production (“HBP”) without near-term lease expirations. Most of those properties offer multiple stacked reservoir objectives with substantial behind pipe potential.
Our shallow Gulf of Mexico shelf properties were acquired during 2013. At December 31, 2013, our shallow Gulf of Mexico shelf properties did not include any producing wells and we were engaged in efforts to seek partners to participate in development of such properties. We continually seek to enhance our acreage position through leasing and evaluation of opportunistic acquisitions both within the transition zone, in the shallow Gulf of Mexico and beyond.
As of December 31, 2012, our total proved reserves were 17.2 MMBoe, consisting of 8.4 MMBbls of oil and 52.9 Bcf of natural gas. The PV-10 of our proved reserves at December 31, 2012 was $407 million, based on SEC pricing. The PV-10 of our proved reserves, based on NYMEX strip pricing, was $443 million. Additionally, we had probable reserves of 13.3 MMBoe, consisting of 5.9 MMBbls of oil and 45.0 Bcf of natural gas. Moreover, our reserve base includes significant undeveloped and exploratory drilling opportunities.
During 2012, we produced 1,116 MBoe, of which 61% was oil. As of December 31, 2012, our development opportunities included 58 proved behind pipe and shut-in opportunities in 7 fields, 89 proved undeveloped opportunities within 28 proposed wells in 4 fields and 31 probable behind pipe and shut-in development opportunities. Additionally, at December 31, 2012, we had 38 probable undeveloped opportunities within 26 proposed wells in 4 fields, 13 possible behind pipe and shut-in development opportunities and 87 possible undeveloped opportunities within 29 wells in 3 fields. During the year ended December 31, 2012, we successfully completed 3 development wells, 2 of which were completed as dual completions, 12 recompletions and 16 workovers.
Our principal and administrative offices are located at 3 Riverway, Suite 1810, Houston, Texas. Our telephone number is (713) 458-1560.
Our Strengths
High-Quality Resource Base. Our principal assets are located in shallow waters on parish and state leases of south Louisiana in fields that are characterized by over 30 years of development drilling and production history. These assets are in close proximity to several other fields operated by leading industry companies such as Apache Corporation, Energy XXI Limited, EPL Oil & Gas, Inc., Helis Oil and Gas Company, Hilcorp Energy Company, Swift Energy Company and Texas Petroleum Investment Company. Additionally, our shallow Gulf of Mexico shelf assets include proved reserves and prospects identified by 3-D seismic and are located in proximity to existing field infrastructure. We believe the quality and location of our properties reduce our development risk and promote operating efficiencies which help to reduce our lifting costs. Additionally, the oil produced by our assets currently commands a premium to WTI crude oil pricing. We also believe that our reserve base has significant undeveloped and exploratory drilling opportunities, which are relatively low risk.
Geographically Focused Assets Without Exposure to Deep Water Operating Risks. Our proved reserves are primarily located in the shallow waters of the Grand Bay Field, Vermilion 16 Field and 10 other established fields on state and parish leases of south Louisiana and, to a lesser degree, in the shallow waters of the Gulf of Mexico shelf. This focused asset base allows us to leverage our technical knowledge of the geological features and operating dynamics within this region. Our geographic focus also enables us to establish economies of scale in both drilling and production operations, allowing us to manage a greater amount of acreage and minimize the marginal costs associated with development activities. Because our present operations are primarily in shallow state waters and, to a lesser extent, in the shallow Gulf of Mexico shelf, we are not exposed to the extreme risk associated with deep water operations. In addition, we are able to avoid the long lead times to first production and ultra-high costs associated with deep water development.
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Extensive Workover and Drilling Inventory. At December 31, 2012, we controlled approximately 32,027 gross/net acres, of which more than half is HBP. Approximately 88% of our proved reserves at December 31, 2012 were classified as proved developed nonproducing and proved undeveloped reserves. We believe our properties hold substantial additional behind pipe reserves beyond the amounts quantified in the proved reserves category and provide us with a significant number of exploration prospects. As of December 31, 2012, our development opportunities included 58 proved behind pipe and shut-in opportunities in 7 fields, 89 proved undeveloped opportunities within 28 proposed wells in 4 fields and 31 probable behind pipe and shut-in development opportunities. Additionally, at December 31, 2012, we had 38 probable undeveloped opportunities within 26 proposed wells in 4 fields, 13 possible behind pipe and shut-in development opportunities and 87 possible undeveloped opportunities within 29 proposed wells in 3 fields. Our 2013 acquisition of Gulf of Mexico acreage has added to our total acreage position and includes proved undeveloped reserves and identified prospects.
High Net Revenue Interests and Operational Control. We own an average net revenue interest in our properties of approximately 75%, which enhances our returns by reducing royalty payments and provides us flexibility in negotiating potential farm-outs, joint ventures, and other opportunities. Additionally, we own a 100% working interest in substantially all of our properties and operate over 98% of the wells that comprise our PV-10 as of December 31, 2012. As an operator, we can more efficiently manage our operating costs, capital expenditures and the timing and method of development of our properties. Our significant operational control and expertise in the area should allow us to operate with a lower cost structure and maximize returns on capital employed.
Control of Infrastructure and Third-Party Processing Revenues. Our extensive infrastructure assets include six production platforms and over 100 miles of pipeline, mostly within the Main Pass and Breton Sound areas. Our infrastructure assets enhance our ability to expand our existing resource base through joint ventures with, and acquisitions of, neighboring producing properties and to generate revenues from third-party handling and processing.
Experienced Management Team. Our directors and executive officers have over 200 combined years of industry experience and a proven track record of successfully leading independent oil and natural gas companies. In addition, our management team has extensive major oil company operational expertise with particular emphasis on cost-control and reservoir management.
Our Strategy
We intend to use our competitive strengths to increase our reserves, production and cash flow. The following are key elements of our strategy:
Grow Through Exploitation, Development and Exploration of Our Properties. We believe that our extensive HBP acreage position will allow us to grow organically through lower-risk development drilling and recompletion work. We have attractive opportunities to expand our reserve base through field extensions, delineating shallower and deeper formations within existing fields and exploratory drilling. Most of our locations offer multiple stacked reservoir objectives with substantial behind pipe potential. We intend to focus our efforts on exploiting our inventory of opportunities with a view to growing our production through a combination of field optimization efforts, including infrastructure upgrades, and conversion of PDNP and proved undeveloped reserves to PDP, and through participation via farm-outs or promoted deals in development of our acreage on the Gulf of Mexico shelf. Our plans are to drill 5 to 6 development wells annually from our existing inventory and to carry out 15 to 20 recompletions, through-tubing plugbacks and workovers annually from our existing inventory. Development work is expected to be spread over several fields with annual capital expenditures associated with these projects expected to be in excess of $40 million and finding and development costs, based on historical performance, targeted at approximately $15 to $20 per Boe. In order to enhance our organic growth initiatives, we have made significant investments in, and will continue to invest in, our infrastructure to support increased handling capacity and create operating efficiencies to lower handling and other operating costs.
Actively Manage the Risks and Rewards of Our Drilling Program. We operate over 98% of the wells that comprise our proved reserves as of December 31, 2012, and we own net revenue interests in our properties that average approximately 75% on a net acreage leasehold basis. We believe operating our properties is important because it allows us to control the timing and costs in our drilling budget, as well as control operating costs and production marketing. In addition, our high net revenue interests enhance our returns from each successful well we drill by generating a higher percentage of cash flow. We believe our high net revenue interests provide us with a unique opportunity to retain a substantial economic interest in riskier wells, including wells that may be drilled on the Gulf of Mexico shelf acreage, while mitigating the risk associated with these projects through farm-outs or promoted deals. Additionally, we will review and rationalize our properties on a continuous basis in order to optimize our existing asset base.
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Leverage Technological Expertise. We believe that 3-D seismic analysis and other advanced technologies and production techniques are useful tools that help improve drilling results and ultimately enhance our production and returns. At December 31, 2012, we either owned or held licenses for 3-D seismic data covering over 450 square miles in Grand Bay and other fields. We intend to utilize these technologies and production techniques in exploring for, developing and exploiting oil and natural gas properties to help us reduce drilling risks, lower finding costs and provide for more efficient production of oil and natural gas from our properties. We believe that the use of these technologies enhances our probability of locating and producing reserves that might not otherwise be discovered.
We have conducted and will continue to complete full field studies over all of our properties. Such field studies include an exhaustive review and integration of well data, wellbore utilization analysis, incorporation of 3-D seismic interpretation results and detailed geological mapping of each sand.
Optimize Development Results and Well Production Through Identification and Development of Horizontal and High Angle Prospects. As a result of our exhaustive field studies, and based on initial drilling results, we believe that our assets offer opportunities to optimize our investment of development capital and resulting production through focusing on the identification and development of horizontal and high angle prospects. Consistent with limited historical horizontal development activities on our properties, we undertook our first horizontal and high angle wells during 2013 with favorable results. We intend to capitalize on our experience in such wells to identify and develop additional horizontal and high angle prospects going forward and, based on results to date, expect to see improved well economics on such prospects.
Pursue Opportunistic Acquisitions. We are an opportunity driven company and, to that end, evaluate potential acquisitions that are compatible with and enhance our growth objectives. We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects. In addition to a large inventory of exploration prospects within our HBP lease position, we have identified a large inventory of exploration prospects in unleased state acreage in close proximity to our existing infrastructure in the Main Pass and Breton Sound areas and shallow Gulf of Mexico shelf acreage that we may pursue in the near future. When identifying acquisition candidates, we focus primarily on underdeveloped assets with significant growth potential that we believe will allow us to enhance and exploit properties without assuming significant geologic, exploration or integration risk.
Properties
The following table describes our properties, proved reserves and production profile at December 31, 2012(1):
Property | Barrels of Oil Equivalent (MBoe) |
| % Oil |
| PV-10(2) (in thousands) |
| Net Acreage (estimated) |
| Net Revenue Interest % |
| Net Producing Wells |
| Reserve Life Index(3) (Years) | |
Grand Bay | 7,241 |
| 64% |
| $ | 210,373 |
| 17,270 |
| 70-79% |
| 51 |
| 16.0 |
Vermilion 16 | 6,069 |
| 27% |
| $ | 88,780 |
| 4,095 |
| 75-83% |
| 1 |
| * |
Main Pass 46 | 1,539 |
| 31% |
| $ | 23,583 |
| 1,662 |
| 74-79% |
| 4 |
| 3.4 |
Other | 2,377 |
| 70% |
| $ | 84,147 |
| 9,000 |
| 75% |
| 30 |
| 4.1 |
All Properties | 17,226 |
| 49% |
| $ | 406,883 |
| 32,027 |
| 75% |
| 86 |
| 11.4 |
*
Not meaningful
(1)
Excludes changes in holdings, reserves, PV-10 and other data during 2013, including changes associated with acquisitions of additional acreage in the Louisiana Transition Zone and in the Shallow Gulf of Mexico Shelf and changes associated with reclassifications and adjustments of certain reserves.
(2)
PV-10 is a non-GAAP financial measure as defined by the SEC. Based on unweighted average benchmark prices as of the first of each month during 2012 of $94.71 per Bbl and $2.76 per MMBtu and before future income taxes. The average realized price after applying differential to unweighted average benchmark prices was $110.06 per Bbl and $3.36 per Mcf.
(3)
Calculated by dividing total net proved reserves by current net production for December 2012.
Louisiana Transition Zone
Our principal producing properties are located in the transitional coastline in protected in-bay environments on parish and state leases in south Louisiana, an area commonly referred to as the “transition zone.” The majority of those properties were acquired in, and we have operated those properties since, 2008. Our properties in the transition zone span 12 fields with principal properties, by production and reserves, being in Grand Bay, Vermillion 16 and Main Pass 46 fields.
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Grand Bay Field. The Grand Bay Field is located in Plaquemines Parish, approximately 70 miles southeast of New Orleans, Louisiana. It is situated in the transitional coastline in a protected in-bay environment on parish and state leases on the east side of the Mississippi River. Gulf Oil Corp. discovered the field in 1938. We are the operator of all of the Grand Bay Field with 100% working interest and an average 70% to 79% net revenue interest. Our leases in the Grand Bay Field, which are all HBP, cover an estimated 17,270 gross and net acres.
The Grand Bay Field is a large, faulted anticlinal structure. It lies on a northwest/southeast trending, deep-seated salt ridge that also sets up Coquille Bay Field, to the northwest, and Romere Pass Field, to the southeast. Trapping is predominantly from intersecting fault closures associated with this anticlinal feature, although there are cases of stratigraphic trapping. The predominant drive mechanism is water drive. Some productive formations are clean, blocky sands with high-resistivity pay. Other laminated, low-resistivity sands are also productive. Shallow sands are predominantly gas-filled and associated with anomalous amplitudes. There are additional shallow amplitudes in the field that have not yet been drilled or logged.
The Grand Bay field has produced oil and gas from over 65 different sand formations located at depths between approximately 1,600 and 13,500 feet. Our field holdings at December 31, 2012 included approximately 67 active wellbores, 46 proved developed nonproducing opportunities and 68 proved undeveloped opportunities in 18 proposed drilling locations within the field. There are also 19 probable developed nonproducing, 27 probable undeveloped opportunities in 20 proposed drilling locations, 12 possible developed nonproducing and 47 possible undeveloped opportunities in 18 proposed drilling locations within the field. We have undertaken a comprehensive full field study approach at Grand Bay Field that is still ongoing. The emphasis of the most recent field study is a detailed mapping of each of the major producing sands, integrating well data and recently reprocessed 3-D data, looking at original reservoir conditions and backing out historical production to see what remains to be developed with infill wells. Based on one previous horizontal well drilled in Grand Bay field, with favorable results, Saratoga is actively seeking horizontal and high angle well candidates as part of its field study of Grand Bay field. Another important part of the study is the geopressured sequence incorporating the Tex L (25 sand) and Cib Carst (43 sand) reservoirs, below 13,000 feet, which has been largely unexplored to date. We have identified multiple opportunities within the sequence and are evaluating partnering with third parties to drill the initial prospect within the sequence.
We own a license to 90 square miles of proprietary 3-D seismic data relating to the Grand Bay Field, which was originally acquired by Greenhill in 1994 and reprocessed by Saratoga in 2008, 2010, 2012 and 2013. We expect to use this dataset to better locate proposed development wells and deep oil and gas targets below existing production.
During 2013, we completed the SL 195QQ-209 “Buddy” well in Grand Bay Field. The Buddy well was drilled during 2012 to a total depth of 6,820 feet MD/TVD and was successfully completed, in early 2013, in the 3A sand. Flow testing of the Buddy well demonstrated an IP rate of 208 net BOEPD. Flowing tubing pressure was 580 pounds per square inch on a 19/64” choke.
Facilities include a central compressor station, four tank batteries, numerous gas lift manifolds and a bunk house, from which all field operations are controlled. Low pressure, high Btu-content gas at Grand Bay Field is used to lift oil and high pressure, lower Btu-content gas. We continue to look for ways to decrease operating costs in all fields.
Vermilion 16 Field. The Vermilion 16 Field is located in the transitional coastline in a protected in-bay environment on state leases offshore Vermilion Parish, approximately 40 miles south of Lafayette, Louisiana. It is situated in approximately 12 feet of water, 0.5 miles offshore in the Gulf of Mexico. We are the operator with a 100% working interest and a net revenue interest ranging from 75% to 83%. The seven existing state leases cover an estimated 4,095 gross/net acres, of which 3,573 net acres are HBP.
The field is a four-way rollover anticline on the downthrown side of a down-to-the-south fault. There are multiple stacked reservoirs within the field. There are 6 wellbores associated with this field and 4 proved undeveloped drilling locations within the field.
Facilities include a central platform and the 6 wellbores associated with the field.
During 2013, pending the results of several high profile ultra-deep wells in the area, we continued to evaluate joint venture and other opportunities to explore ultra-deep prospects in Vermilion 16 Field.
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Main Pass 46 Field. The Main Pass 46 Field is located in the transitional coastline in a protected in-bay environment on state leases offshore Plaquemines Parish, approximately 80 miles south-southeast of New Orleans, Louisiana. The field is situated in approximately six feet of water, immediately north of Grand Bay Field. We are the operator with a 100% working interest and a net revenue interest ranging from 74% to 79%. The four existing state leases cover an estimated 1,662 gross/net acres and are all HBP.
The field is a faulted anticlinal structure with outlying stratigraphic traps. There are multiple stacked reservoirs within the field. The Main Pass 46 Field is partly covered by the 90 square mile proprietary 3-D Grand Bay survey.
Facilities include a central platform and the 5 active wellbores associated with the field. All of the 11 proved undeveloped opportunities in 3 proposed new wellbores are located within Grand Bay State Lease 195.
Other Fields. We hold interests in 9 other fields, all of which are located in shallow waters on state leases in Plaquemines, St. Bernard and St. Mary parishes of southern Louisiana, with 100% working interests in all fields, except for the Main Pass 47 Field, where we have a 7.5% overriding royalty interest in one producing well. Our net revenue interests in these fields average 75%. The leases, which are mostly HBP, cover 9,000 gross/net acres.
Among the other fields in which we hold interests are the Main Pass and Breton Sound fields, which are a series of stratigraphic trap-type fields in the Middle Miocene trend that were discovered with 3-D seismic technology. The reservoir drive mechanisms are water drive and combination water drive/pressure depletion. We have licensed the entire SEI Breton Sound 3-D survey that covers approximately 400 square miles.
During 2013, we drilled and completed the “Rocky” well in Breton Sound 32 field which targeted an elongated ridge, offsetting the SL 1227 #21 and #22 wells in the 5,800’ sand, which is the main producing reservoir in the Breton Sound 32 field. A seventy-degree pilot hole was drilled followed by a sidetrack with a 750’ lateral completion. This well was our first horizontal well. The Rocky well had an IP rate of gross 600 BOPD, 120 MCFPD on a 16/64” choke with 650# FTP (net 508 BOEPD).
During 2013, we also drilled the “Zeke” well in Breton Sound 32 which also targeted the same 5,800’ sand but in a separate structure to the south-east and was completed as a high angle (82 degrees) directional. The Zeke well also established a previously unbooked uphole recompletion opportunity in the overlying 5,750’ sand, which also produces within the field. The Zeke well had an IP rate of gross 312 BOPD, 89 MCFPD on a 38/64” choke with 480# FTP (net 268 BOEPD).
Gulf of Mexico Shelf.
In July 2013, we were awarded four leases, with seismic maps included, totaling 19,814 acres in the Central Gulf of Mexico Lease Sale 227. The acreage is in the shallow Gulf of Mexico shelf in water depths of 13 to 77 feet. Two of the leases are in the Vermilion area and two of the leases are in the Ship Shoal area. The leases have a primary term of five years and can be extended for an additional three years. Lease bonuses on the prospects totaled $880,000 and we paid a prospect fee of $500,000 to a third party consultant. The cost of the leases, in the amount of $1,380,000, has been recorded in oil and gas properties at September 30, 2013. Annual rentals on the leases total $138,698 during the primary term.
Using 3-D surveys included with the leases, four initial prospects have been identified within the Gulf of Mexico shelf acreage. We are seeking partners to drill the first of the prospects during 2014. The acreage includes proved undeveloped reserves at December 31, 2013 of 2.74 MMBOE.
Field Infrastructure
We own significant infrastructure assets that are used to service our properties and third-party customers, including over 100 miles of pipeline connecting several of the fields as well as outlying wellheads. There are six platform facilities plus 86 active producing wellbores associated with these fields, including ten saltwater disposal wells. Facilities at the Grand Bay Field include four tank batteries, a compressor station, various flowlines and a bunk house. In addition to serving our wells and improving field economics, we generate processing and production handling revenues from third-party customers.
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Oil and Natural Gas Reserves
Reserve Estimates
SEC Case. The following tables sets forth, as of December 31, 2012, our estimated net proved oil and natural gas reserves, the estimated present value (discounted at an annual rate of 10%) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves and our estimated net probable and possible oil and natural gas reserves, each prepared in accordance with assumptions prescribed by the Securities and Exchange Commission (SEC). All of our reserves are located in the United States.
The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent. PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the estimated discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carryforwards and other factors. We believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.
| Reserves(1) | |||||
Reserve category | Oil (MBbls) |
| Natural Gas (MMcf) |
| Total(2) (MBoe) | |
Proved |
|
|
|
|
|
|
Developed |
|
|
|
|
|
|
Producing | 1,367 |
| 3,868 |
|
| 2,012 |
Shut-in | 162 |
| 1,076 |
|
| 341 |
Behind Pipe | 1,280 |
| 4,216 |
|
| 1,983 |
Total Proved Developed | 2,809 |
| 9,160 |
|
| 4,336 |
Undeveloped | 5,597 |
| 43,759 |
|
| 12,890 |
Total Proved | 8,406 |
| 52,919 |
|
| 17,226 |
Probable(3) |
|
|
|
|
|
|
Developed | 663 |
| 5,047 |
|
| 1,504 |
Undeveloped | 5,187 |
| 39,934 |
|
| 11,843 |
Possible(3) |
|
|
|
|
|
|
Developed and Undeveloped | 5,851 |
| 117,257 |
|
| 25,394 |
PV-10(1) (in thousands) |
|
|
|
| $ | 406,883 |
Standardized Measure(4) (in thousands) |
|
|
|
| $ | 292,685 |
_____________________________
(1)
In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2012. For purposes of determining prices, we used the unweighted arithmetical average of the prices on the first day of each month within the 12-month period ended December 31, 2012 which were $94.71 per Bbl and $2.76 per MMBtu. The prices utilized for purposes of estimating our proved reserves were $110.06 per Bbl and $3.36 per Mcf, after adjustment by property for energy content, quality, transportation fees and regional price differentials. The prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.
(2)
Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.
(3)
Probable and possible reserves have not been discounted for the risk associated with future recovery.
(4)
The Standardized Measure differs from PV-10 only in that the Standardized Measure reflects estimated future income taxes.
Due to the inherent uncertainties and the limited nature of reservoir data, proved, probable and possible reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
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In estimating probable and possible reserves, it should be noted that those reserve estimates inherently involve greater risk and uncertainty than estimates of proved reserves. While analysis of geoscience and engineering data provides reasonable certainty that proved reserves can be economically producible from known formations under existing conditions and within a reasonable time, probable reserves involve less certainty with reserves supporting a probable classification from a probabilistic analysis where those reserves are “as likely as not to be recovered.” Possible reserves involving even less certainty than probable reserves and possible classification is supported when there is at least a 10% probability that total quantities recovered equal or exceed proved plus probable plus possible reserve estimates.
Alternative Pricing Case. We use forward-looking market-based data in developing our drilling plans, assessing our capital expenditure needs and projecting future cash flows. We believe that using the 10-year average NYMEX strip prices yields a better indication of the likely economic producibility of proved reserves than the trailing average 12-month price required by SEC reserves rules. The table below compares our estimated proved reserves and associated present value (discounted at an annual rate of 10%) of estimated future revenue before income taxes using the 2012 12-month average prices reflected in our reported reserve estimates and the 10-year average future NYMEX strip prices as of December 31, 2012.
| Oil (MBbls) |
| Gas (MMcf) |
| Total (MBoe)(1) |
| PV-10 (in thousands) |
SEC Case | 8,406 |
| 52,919 |
| 17,226 |
| $406,883 |
NYMEX Strip Price Case(2) | 8,395 |
| 53,480 |
| 17,308 |
| $442,580 |
___________________________
(1)
Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.
(2)
The NYMEX Strip Pricing Case discloses our estimated proved reserves using future market-based commodities prices instead of the average historical prices used in the SEC Case. Under the NYMEX Strip Pricing Case, we used futures prices, as quoted on the New York Mercantile Exchange (“NYMEX”) on December 31, 2012, as benchmark prices for 2012 through 2018, and continued to use the 2018 futures price for all subsequent years. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $85.92 per barrel of oil and $4.88 per Mcf of natural gas over the remaining life of the proved reserves. There is no change to our cost or other assumptions between this higher price scenario and those used in the estimation of our reported reserves.
Interim Reserve Estimates
During 2013, we prepared an internal unaudited reserve estimate, as of October 1, 2013, in connection with our offering of First Lien Notes. Additionally, we prepared year-end reserve estimates with respect to our newly acquired Gulf of Mexico assets, which estimates were reviewed by an outside reserve engineering firm.
Our October 1, 2013 internal unaudited reserve estimate reflected total proved reserves of 14.39 MBoe with a PV-10 of $343.8 million for state and parish leases only. That estimate reflects10.4 MBoe of proved undeveloped reserves after removing from such category 2.4 MMBoe as a result of the anticipated application, at year-end 2013, of the SEC “five year” rule under which proved undeveloped reserves are generally to be removed from presentation as proved reserves if not developed within five years of initially being booked in such category.
Year-end 2013 reserves associated with Gulf of Mexico assets are estimated to include total proved reserves, all of which are undeveloped, of 2.74 MMBoe with a PV-10 of $37.2 million.
Reserve Estimation Process, Controls and Technologies
The reserve estimates, including PV-10 and Standard Measure estimates, at December 31, 2012 were prepared by Collarini Associates for our transition zone reserves and the reserve estimates at year-end 2013 were prepared by DeGolyer and MacNaughton for our Gulf of Mexico shelf reserves.
These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.
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We maintain an internal staff of engineering and geoscience professionals, supplemented by consultants, who work closely with Collarini Associates and DeGolyer and MacNaughton (the “outside reserve engineers”) in connection with their preparation of our reserve estimates, including assessing the integrity, accuracy and timeliness of the methods and assumptions used in this process. Our technical team members meet with outside reserve engineers periodically throughout the year to discuss the assumptions and methods used in the reserve estimation process. We provide historical information to the outside reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. The activities of our staff are led and overseen by our President, a degreed petroleum geologist/geophysicist with over 30 years of technical experience involving petroleum reserve assessment and estimation and geoscience-based evaluation. He is assisted by our Asset Evaluation Manager, who has over 25 years of technical experience in petroleum engineering and reservoir evaluation and analysis. Together, these individuals direct the activities of our engineering and geosciences staff who coordinate with our accounting and other departments to provide the appropriate data to the outside reserve engineers in support of the reserve estimation process and to assure that information derived from the outside reserve engineers’ reports is properly disclosed in our reports.
Collarini Associates is an independent Houston and New Orleans-based professional engineering firm specializing in technical and financial evaluation of oil and gas assets. Their report was prepared under the direction of Collarini Associates’ President and Engineering Manager. Collarini Associates’ Engineering Manager holds a B.S. in petroleum engineering from Texas A&M University, is a registered professional engineer and has approximately 30 years of experience in production engineering, reservoir engineering, acquisitions and divestments, field operations and management.
DeGolyer and MacNaughton is an independent Dallas-based professional engineering firm providing reserve engineering and other services to the oil and gas industry worldwide. Their report was prepared under the direction of Gregory Graves, Senior Vice President. Mr. Graves holds a B.S. in petroleum engineering from the University of Texas, completed post-baccalaureate studies in micro- and macroeconomics at the University of Houston, is a licensed professional engineer and a member of the Society of Petroleum Evaluation Engineers. Mr. Graves has more than 30 years experience in the energy industry.
The SEC’s rules with respect to technologies that a company can use to establish reserves, effective for years ending after December 31, 2008, allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
The outside reserve engineers used a combination of production and pressure performance, simulation studies, offset analogies, seismic data and interpretation, geophysical logs and core data to calculate our reserves estimates.
Proved Undeveloped Reserves
As of December 31, 2012, our proved undeveloped reserves totaled 5.6 MMBbls of oil and 43.8 Bcf of natural gas, for a total of 12.9 MMBoe compared to 5.4 MMBbls of oil and 55.9 Bcf of natural gas, for a total of 14.7 MMBoe as of December 31, 2011. The change in our proved undeveloped reserves was attributable to a loss of reserves (2,637 MBoe) associated with the Vermilion 16 field following the drilling of the Mesa Verde well, a further loss of reserves (315 Mboe) due to economic limit revisions relating to prices and conversion of proved undeveloped reserves to proved developed (approximately 888 MBoe), partially offset by new additions due to field studies in Breton Sound 32 and Grand Bay fields (950 MBoe), and due to successful development drilling at Breton Sound 18 and Grand Bay fields (517 MBoe).
All of our proved undeveloped reserves at December 31, 2012 were associated with our Louisiana properties.
We incurred costs relating to the development of proved undeveloped reserves of $39.8 million and $11.3 million during 2012 and 2011, respectively.
All proved undeveloped locations are scheduled to be drilled or otherwise converted to proved developed reserves before the end of 2017. As of December 31, 2012, none of our proved undeveloped locations had been booked for longer than five years.
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Production, Price and Production Cost History
The table below sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sale of oil and natural gas for the three years ended December 31, 2012.
| 2010 |
| 2011 |
| 2012 | |||
Net Production: |
|
|
|
|
|
|
|
|
Oil (Bbl) |
| 550,000 |
|
| 605,900 |
|
| 676,400 |
Natural gas (Mcf) |
| 1,882,800 |
|
| 2,038,000 |
|
| 2,639,500 |
Combined volumes (Boe) |
| 863,800 |
|
| 945,567 |
|
| 1,116,317 |
Average sales price per Boe | $ | 61.05 |
| $ | 80.54 |
| $ | 73.93 |
Average production cost per Boe(1) | $ | 18.44 |
| $ | 20.93 |
| $ | 20.74 |
_________________________
(1)
Average production cost per Boe excludes severance taxes.
Drilling and Development Activity
The following table summarizes our drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. We have had a 100% success rate in developmental drilling over the past three years and an 86% success rate on all drilling over the last three years.
|
| 2010 |
| 2011 |
| 2012 | ||||||
|
| Gross |
| Net |
| Gross |
| Net |
| Gross |
| Net |
Exploratory Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
Unproductive |
| 0 |
| 0 |
| 1 |
| 1 |
| 0 |
| 0 |
Total |
| 0 |
| 0 |
| 1 |
| 1 |
| 0 |
| 0 |
Developmental Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
| 1 |
| 1 |
| 2 |
| 2 |
| 3 |
| 3 |
Unproductive |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
| 0 |
Total |
| 1 |
| 1 |
| 2 |
| 2 |
| 3 |
| 3 |
Success Ratio (1) |
| 100% |
| 100% |
| 67% |
| 67% |
| 100% |
| 100% |
(1)
The success ratio is calculated as follows: (total wells drilled—non-productive wells—wells awaiting completion)/(total wells drilled—wells awaiting completion).
A well’s completion is reported in the year of completion regardless of when drilling was initiated. Productive wells are wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
In addition to the wells completed, during 2012 we successfully completed 11 out of 12 recompletion and 16 workover operations and during 2011 we successfully completed 7 out of 9 recompletion and 25 workover operations.
The foregoing information should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered by us. We do not own any drilling rigs and all of our drilling activities are conducted by independent drilling contractors.
At December 31, 2012, one well had been drilled and logged, but was awaiting completion. There were no recompletion or workover operations being conducted at year end.
Productive Wells
The following table sets forth information with respect to our ownership interest in productive wells, all of which are located in the United States, as of December 31, 2012:
| Gross |
| Net |
Oil wells | 92 |
| 91 |
Gas wells | 13 |
| 13 |
Total | 105 |
| 104 |
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Productive wells are producing wells and wells mechanically capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. Wells with multiple completions are counted as one well in the table above. The total gross wells at December 31, 2012 included 5 wells with multiple completions.
Developed and Undeveloped Acreage
The following table sets forth information with respect to our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2012(1):
Developed Acreage |
| Undeveloped Acreage |
| Total Acreage | ||||||
Gross |
| Net |
| Gross |
| Net |
| Gross |
| Net |
31,505 |
| 31,505 |
| 522 |
| 522 |
| 32,027 |
| 32,027 |
______________________
(1)
Excludes Gulf of Mexico acreage acquired during 2013 as well as other changes in acreage positions during 2013.
Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well. Undeveloped acreage is comprised of leased acres with defined remaining terms and not within an area spaced by or assignable to a productive well.
As is customary in the oil and natural gas industry, we can generally retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from our developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced.
Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production.
Marketing, Customers and Pricing
General
We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.
Marketing
Effective April 1, 2010, we entered into a Natural Gas, Crude and Processing Marketing/Administration Agency Agreement pursuant to which Transparent Energy Services, Inc. markets substantially all of our oil and natural gas production.
We generally market our oil and natural gas production under “month-to-month” or “spot” contracts.
We receive a premium price for our Light Louisiana Sweet (LLS) and Heavy Louisiana Sweet (HLS) crude oil produced. We attribute this premium pricing to the high quality and geographic location of the crude oil product. This combination of production location and crude oil quality have allowed us to sell our crude oil at prices above WTI price postings during the second half of 2011 and 2012, and we anticipate that market conditions should allow us to continue to receive pricing above WTI postings into 2013. At December 31, 2012, we were marketing our crude oil at prices that were averaging approximately $19.08 per bbl above WTI price postings.
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Sales of oil and gas production to Shell Trading (US) Company and Shell Energy North America (US), L.P. (collectively “Shell”) accounted for 35.5% and 94.0% of our consolidated sales in 2012 and 2011, respectively. In addition, sales of oil and gas production to Plains Marketing and J. P. Morgan Ventures Energy Corp. accounted for 33.4% and 12.3%, respectively, of our consolidated sales in 2012. We believe that the loss of any of these purchasers would not have a material adverse effect on us because alternative purchasers are readily available.
Derivatives
During the third quarter of 2012, we resumed our hedging program which had previously been suspended in February 2010. We use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and future capital programs. From time to time, we may enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts; however, it is our preference to utilize hedging strategies that provide downside commodity price protection without unduly limiting our revenue potential in an environment of rising commodity prices. We use hedging primarily to manage price risks and returns on certain drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive.
Shell Trading (US) Company is the counterparty to each of our present forward physical contracts and fixed price swap contracts. We are exposed to credit losses in the event of nonperformance by the counterparty on our commodity derivatives positions. However, we do not anticipate nonperformance by the counterparty over the term of the commodity derivatives positions.
Competition
We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies, numerous independent oil and gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and gas business for a much longer time than our company. These companies may be able to pay more for productive oil and gas properties, exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Employees
As of December 31, 2013, we had 34 full time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are positive. From time to time, we utilize the services of independent contractors to perform various field and other services.
Regulation of the Oil and Gas Industry
The oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments. Compliance with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. Most jurisdictions in which we operate also have statutes, rules, regulations or guidelines governing the conservation of natural resources, including the unitization or pooling of oil and gas properties and the establishment of maximum rates of production from oil and gas wells. Some jurisdictions also require the filing of drilling and operating permits, bonds and reports. The failure to comply with these statutes, rules and regulations could result in the imposition of fines and penalties and the suspension or cessation of operations in affected areas.
We operate various gathering systems and pipelines servicing the areas in which we operate. The United States Department of Transportation and certain governmental agencies regulate the safety and operating aspects of the transportation and storage activities of these facilities by prescribing standards. However, based on current standards concerning transportation and storage activities and any proposed or contemplated standards, we believe that the impact of such standards is not material to our operations, capital expenditures or financial position. All of our sales of our natural gas are currently deregulated, although governmental agencies may elect in the future to regulate certain sales.
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Regulation of Transportation and Sale of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Interstate oil pipeline rates are typically set based on a cost of service methodology (“Cost-Based Rates”); however, they may also be set based on the competitive market (“Market-Based Rates”) or by agreement between the pipeline and its shippers (“Settlement Rates”). Some oil pipeline rates may be increased pursuant to an index methodology, whereby the pipeline may increase its rates up to a ceiling set by reference to the Producer Price Index for Finished Goods (unless the rate increase is shown to be substantially in excess of the actual cost increases incurred by the pipeline). Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Regulation of Transportation and Sale of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on shore and in state waters. Although its policy is still in flux, the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point of sale locations.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
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Environmental Regulation
Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the discharge and disposition of generated waste materials and waste management, the reclamation and abandonment of wells, sites and facilities, financial assurance under the Oil Pollution Act of 1990 and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.
We routinely obtain permits for our facilities and operations in accordance with applicable laws and regulations on an ongoing basis. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations.
The ultimate financial impact of environmental laws and regulations is neither clearly known nor easily determined as new standards are enacted and new interpretations of existing standards are rendered. Environmental laws and regulations are expected to have an increasing impact on our operations. In addition, any non-compliance with such laws could subject us to material administrative, civil or criminal penalties, or other liabilities. Potential permitting costs are variable and directly associated with the type of facility and its geographic location. Costs, for example, may be incurred for air emission permits, spill contingency requirements, and discharge or injection permits. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.
We are committed to the protection of the environment throughout our operations and believe our operations are in substantial compliance with applicable environmental laws and regulations. We believe environmental stewardship is an important part of our daily business and will continue to make expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully insured against all such risks. The insurance coverage maintained by us provides for the reimbursement to us of costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure pollution and similar environmental risks. We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated and combined financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.
The environmental laws and regulations applicable to us and our operations include, among others, the following United States federal laws and regulations:
•
Resource Conservation and Recovery Act, which governs the management of solid waste;
•
Comprehensive Environmental Response, Compensation and Liability Act, which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”);
•
Clean Water Act, which governs discharges to waters of the United States;
•
Oil Pollution Act of 1990, which imposes liabilities resulting from discharges of oil into navigable waters of the United States;
•
Clean Air Act, and its amendments, which govern air emissions;
•
Emergency Planning and Community Right-to-Know Act, which requires reporting of toxic chemical inventories;
•
Safe Drinking Water Act, which governs the underground injection and disposal of wastewater;
•
Endangered Species Act and Migratory Bird Treaty Act, which prohibit certain actions that adversely affect endangered or threatened species and migratory birds and their habitat;
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•
U.S. Department of Interior and U.S. Environmental Protection Agency regulations, which impose liability for pollution cleanup and damages; and
•
Occupational Safety and Health Act (OSHA) and comparable state laws and regulations that establish workplace standards for the protection of the health and safety of employees.
The following is a summary of certain existing laws, rules and regulations to which our business operations are subject:
Waste Handling
The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are not currently regulated under RCRA or state hazardous waste provisions though our operations may produce waste that does not fall within this exemption. However, these oil and gas production wastes may be regulated as solid waste under state law or RCRA. It is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
Comprehensive Environmental Response, Compensation, and Liability Act
The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the Superfund Law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
In the course of our operations, we generate wastes that may fall within CERCLA’s definition of hazardous substances. Further, we currently own, lease or operate properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances or petroleum may have been released on, at, under or from the properties owned, leased or operated by us, or on, at, under or from other locations, including off-site locations, where such hazardous substances or other wastes have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances, petroleum, or other materials or wastes were not under our control. These properties and the substances or materials disposed or released on, at, under or from them may be subject to CERCLA, RCRA or analogous or other state laws. Under such laws, we could be required to remove previously disposed hazardous substances and address any resulting impacts.
Water Discharges
The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
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The Oil Pollution Act of 1990, or OPA, which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. In addition, OPA and regulations promulgated pursuant thereto impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. OPA also requires certain oil and natural gas operators to develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance.
Air Emissions
The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. Oil and gas operations may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants, including volatile organic compounds, nitrous oxides, and hydrogen sulfide.
Endangered Species, Wetlands and Damages to Natural Resources
Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration or production or seek damages to species, habitat, or natural resources resulting from filling or construction or releases of oil, wastes, hazardous substances or other regulated materials.
Climate Change Legislation and Greenhouse Gas Regulation
Federal, state and local laws and regulations are increasingly being enacted to address concerns about the effects the emission of “greenhouse gases” may have on the environment and climate worldwide. These effects are widely referred to as “climate change.” Since its December 2009 endangerment finding regarding the emission of greenhouse gases, the EPA has begun regulating sources of greenhouse gas emissions under the federal Clean Air Act. Among several regulations requiring reporting or permitting for greenhouse gas sources, the EPA finalized its “tailoring rule” in May 2010 that determines which stationary sources of greenhouse gases are required to obtain permits to construct, modify or operate on account of, and to implement the best available control technology for, their greenhouse gases. In November 2010, the EPA also finalized its greenhouse gas reporting requirements, beginning in March 2012, for certain oil and gas production facilities.
Moreover, in the recent past the U.S. Congress has considered establishing a cap-and-trade program to reduce U.S. emissions of greenhouse gases. Under past proposals, the EPA would issue or sell a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of such legislation, if ever adopted, would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products, and natural gas. In addition, while the prospect for such cap-and-trade legislation by the U.S. Congress remains uncertain, several states have adopted, or are in the process of adopting, similar cap-and-trade programs.
As a crude oil and natural gas company, the debate on climate change is relevant to our operations because the equipment we use to explore for, develop and produce crude oil and natural gas emits greenhouse gases. Additionally, the combustion of carbon-based fuels, such as the crude oil and natural gas we sell, emits carbon dioxide and other greenhouse gases. Thus, any current or future federal, state or local climate change initiatives could adversely affect demand for the crude oil and natural gas we produce by stimulating demand for alternative forms of energy that do not rely on the combustion of fossil fuels, and therefore could have a material adverse effect on our business. Although our compliance with any greenhouse gas regulations may result in increased compliance and operating costs, we do not expect the compliance costs for currently applicable regulations to be material. Moreover, while it is not possible at this time to estimate the compliance costs or operational impacts for any new legislative or regulatory developments in this area, we do not anticipate being impacted to any greater degree than other similarly situated competitors.
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Web Site Access to Reports
Our Web site address is www.saratogaresources.com. We make available, free of charge on or through our Web site, our annual report, Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the United States Securities and Exchange Commission. Information contained on, or accessible through, our website is not incorporated by reference into this prospectus.
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LEGAL PROCEEDINGS
Ad Valorem Tax Litigation – Plaquemines Parish, Louisiana
In December 2009, the Parish of Plaquemines, State of Louisiana, filed supplemental assessments against multiple oil and gas companies, including Saratoga and/or its subsidiaries, for allegedly omitting or undervaluing oil producing assets on the annual self-reporting tax renditions used to calculate ad valorem taxes. In short, the difference between what was reported by the oil and gas companies and what the assessor taxed boiled down to how depreciation of the oil and gas related equipment was calculated and how certain equipment was classified. The amount alleged to be due by Saratoga for the years 2006, 2007, and 2008 is $1.3 million in Parish taxes. Also at issue are the increased assessment valuations for the years 2009, 2010, and 2011 brought by the Parish under the same theory. Saratoga contested the additional tax assessments in an action styled Aviva America, Inc., The Harvest Group, LLC, Harvest Oil & Gas, LLC, Saratoga Resources, Inc., Lobo Operating, Inc. and Lobo Resources, Inc. v. Robert R. Gravolet, In His Capacity as Assessor for Plaquemines Parish, Louisiana, 25th Judicial District Court for the Parish of Plaquemines, and, as to certain issues relating to such claims, a number of administrative proceedings before the Louisiana Tax Commission.
The Harvest Group, LLC, et al. v. Barry Ray Salsbury, et al.
In February 2010, Saratoga filed a complaint in the United States Bankruptcy Court for the Western District of Louisiana against Barry Ray Salsbury, Brian Carl Albrecht, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer, each being former owners of The Harvest Group LLC and/or Harvest Oil & Gas, LLC. The complaint alleged breach of the Purchase and Sale Agreements with the former owners arising from the underpayment or nonpayment of royalties to the State of Louisiana for periods prior to Saratoga’s acquisition of the Harvest Companies and related claims for damages. Specifically, the complaint alleged that the underpayment or nonpayment of such royalties constituted a breach, by the former owners, of the representations and warranties that all royalty payments of the Harvest Companies had been paid in full as of the closing of Saratoga’s purchase of the Harvest Companies. Saratoga subsequently amended its complaint to add to the breach of contract claims additional claims based on fraud arising from the willful and knowing concealment of the underpayment of royalties. In its amended complaint, Saratoga named Henry Calongne and Professional Oil & Gas Marketing as additional defendants based on substantially identical facts as alleged in the complaint against the former owners of the Harvest Companies. Mr. Calongne and Professional Oil & Gas Marketing served as the agent of the Harvest Companies in computing the applicable royalty payments. Saratoga has asserted that Mr. Calongne and Professional Oil & Gas Marketing either negligently or knowingly colluded with the former owners with respect to the underpayment of royalties to the State of Louisiana. Saratoga was seeking monetary damages with the total principal claims against all defendants being $1.4 million. In addition, certain of the former owners asserted a counterclaim for $0.2 million for improper collection of joint interest billing credits and Professional Oil & Gas Marketing asserted counterclaims against Saratoga for $0.2 million for unpaid fees and reimbursable tax payments. During 2012, Saratoga concluded settlements with Barry Ray Salsbury, Shell Sibley, Willie Willard Powell and Carolyn Monica Greer and received approximately $769,000 and the claims and counterclaims involving those defendants were dismissed. In 2012, the case with respect to the remaining defendants was removed to the U.S. District for the Southern District of Louisiana. During 2013, Henry Calongne and Professional Oil and Gas Marketing were granted partial summary judgment and awarded $126,280 of marketing fees with said amount being placed in escrow pending final resolution of Saratoga’s claims against each. Litigation is still pending as to the remaining defendants, including Brian Carl Albrecht, Professional Oil and Gas Marketing, and Henry Calongne. The claim against Mr. Albrecht has been converted to an arbitration proceeding and the claims against Mr. Calogne and Professional Oil and Gas Marketing are set for trial in March 2014.
Harvest Operating, LLC v. The Harvest Group, LLC, et. al.
In October 2013, Harvest Operating, LLC, a company owned by Brian Carl Albrecht, filed a complaint in the 25th Judicial District Court, Plaquemines Parish, Louisiana against The Harvest Group, LLC and Saratoga. The complaint alleges breach of contract and bad faith based on the defendants’ alleged prohibition of the plaintiff from use certain flowlines to transport oil and gas production. The plaintiff has not specified its alleged damages but has alleged that it was forced to shut in one well and sell another well at a reduced rate based on the alleged acts of the defendants. We have only recently been served in the lawsuit and are reviewing the merits of the claim. The lawsuit has since been converted to an arbitration.
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Board of Commissioners of the Southeast Flood Protection Authority-East, et al. v. Tennessee Gas Pipeline Company, LLC et al.
In July 2013, the Southeast Louisiana Flood Protection Authority – East (the “Levee Board”) filed suit in Civil District Court, Orleans Parish naming 97 oil and gas companies as defendants, including Harvest Oil & Gas, LLC. The lawsuit alleges that defendants are liable to the Levee Board for damages resulting from years of ongoing oil and gas activity. The causes of action asserted by the Levee Board include, but are not limited to, negligence, breach of contract, preliminary injunction, strict liability, natural servitude of drain, public nuisance, etc. The case was removed from state court to federal court (U.S. District Court for the Eastern District of Louisiana) in September 2013. Since then, the parties have filed briefs relating to the legal question of whether the case should stay in federal court or be remanded to state court. The hearing on the motion to remand was heard by the court on December 18, 2013, but the ruling is under advisement.
We may from time to time be a party to lawsuits incidental to our business. Except as noted above, as of December 31, 2013, we were not aware of any current, pending, or threatened litigation or proceedings that could have a material adverse effect on our results of operations, cash flows or financial condition.
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MANAGEMENT
Executive Officers
Our executive officers as of December 31, 2012, and their ages and positions as of that date, were as follows:
Name |
| Age |
| Position |
Thomas F. Cooke |
| 64 |
| Chief Executive Officer and Chairman |
Andrew C. Clifford |
| 58 |
| President |
Michael Aldridge |
| 54 |
| Executive Vice President and Chief Financial Officer |
Brian Daigle |
| 53 |
| Vice President – Operations |
Randal McDonald, Jr. |
| 55 |
| Controller |
The following is a biographical summary of the business experience of our executive officers:
Thomas F. Cooke co-founded our company in 1990 and has served as our Chief Executive Officer and Chairman since October 2007. Mr. Cooke served as our President, Chief Executive Officer and Chairman from 1996 to 2007. In addition, Mr. Cooke has been self-employed as an independent oil and gas producer and investor for more than 30 years.
Andrew C. Clifford has served as our President and a Director since October 2007. He is a petroleum geologist/geophysicist with over 33 years of experience. Mr. Clifford’s experience includes providing professional geological services on prospects throughout the United States and around the world as an independent consultant, as Vice President of Exploration for BHP Petroleum and as a Senior Geophysicist for BHP Petroleum, Kuwait Foreign Petroleum and Esso Exploration. Prior to joining the company, Mr. Clifford was a co-founder and Executive Vice President of Aurora Gas, LLC, an independent gas developer and producer with gas production operations in Cook Inlet, Alaska. Mr. Clifford holds a B.Sc, with honors, in Geology with Geophysics from London University and is a frequent speaker and published author on a variety of energy industry topics.
Michael Aldridge served as our Executive Vice President and Chief Financial Officer from October 2011 until December 2013. Prior to joining our company, from 2000 to 2008, Mr. Aldridge served in various executive roles with Petroquest Energy, Inc., an NYSE-listed independent oil and gas company, including serving as Chief Financial Officer and a Director commencing in 2000, as Treasurer commencing in 2001 and as Executive Vice President commencing in 2006. From 2009 until joining our company, Mr. Aldridge served as a financial consultant to the energy industry. From 1992 to 1999, Mr. Aldridge served first as Vice President — Controller and then as Vice President — Corporate Communications for Ocean Energy, Inc., a public oil and gas exploration and development company. From 1991 to 1992, he served as Chief Financial Officer for Fleet Petroleum Partners, an independent exploration and production company. Prior to this, he served the oil and gas industry for eleven years with Ernst & Young LLP, where he attained the level of Senior Manager. Mr. Aldridge earned a Bachelor of Science in Accounting from Louisiana State University and is a Certified Public Accountant.
Brian Daigle has served as our Vice President – Operations since July 2010. Previously, Mr. Daigle served as Operations Manager of Harvest Oil and Gas, LLC and The Harvest Group, LLC (together, the “Harvest Companies”) since 2006 and is responsible for the day-to-day management of the companies’ physical assets. Prior to joining the Harvest Companies, from 2004 to 2006 Mr. Daigle was self-employed as a consultant to various operators providing operations management, technical support for facility installation, and managing daily production operations. Mr. Daigle served as Production Superintendent for Denbury Resources from 2001 to 2004. Mr. Daigle has more than 25 years of diversified experience in the oil and gas industry — focused on production operations, facility design, regulatory compliance, and project management in the Gulf of Mexico and inland waters of the State of Louisiana.
Randal McDonald, Jr. has served as our Controller since November 2011. Previously, from 2007 to 2011, Mr. McDonald served as Controller of Baseline Oil & Gas Corp., an independent oil and gas company. From 1998 until 2007, Mr. McDonald served as Chief Financial Officer and a Director of VTEX Energy, Inc., a publicly traded independent oil and gas company. Mr. McDonald holds a B.B.A. degree in Accounting from the University of Texas at Austin and is a licensed Certified Public Accountant.
There are no family relationships among the executive officers and directors. Except as otherwise provided in employment agreements, each of the executive officers serves at the discretion of the Board.
78
Changes in Executive Officers
In November 2013, John Ebert was appointed Vice President – Finance and Business Development and in December 2013, Michael Aldridge resigned as our Chief Financial Officer.
John Ebert has served as our Vice President – Finance and Business Development since November 2013 after joining our company in a business development capacity in August 2013. Prior to joining our company, from 2011 to 2013, Mr. Ebert was a consulting partner in ETROA Resources, LLC, an oil and gas investment and development firm located in Covington, Louisiana and focused on Gulf Coast onshore and offshore resources. Mr. Ebert held various positions with Woodside Energy from 2005 until 2011, beginning as a senior reservoir engineer and adding the roles of Engineering Manager, Senior Manager Business Planning, and Vice President of Finance. Mr. Ebert has more than 20 years of industry experience in finance, business development and reservoir engineering with a focus on the Gulf Coast region.
Directors
Our directors as of December 31, 2012, and their ages, principal occupations and business experience as of that date, were as follows:
Thomas F. Cooke. See biography above.
Andrew C. Clifford. See biography above.
Kevin M. Smith, age 68, has been the owner and principal of Kevin M. Smith, Inc., a geophysical consulting firm since 1984. Mr. Smith holds a B.S. in Geology and Geophysics from the University of Houston.
John W. Rhea, IV, age 60, is the owner and principal of J.W. Rhea & Associates, a petroleum exploration consulting firm, since 2009. Mr. Rhea served as a director, and in various executive positions including Chief Executive Officer, Chief Operating Officer and President, of Latitude Solutions, Inc., from July 2012 to November 2012. Latitude Solutions filed for protection under Chapter 7 of the U.S. Bankruptcy Code in November 2012. Mr. Rhea served as President, Chief Executive Officer and a Director, Gulf Energy Exploration Corp., a privately held oil and gas exploration and production company with principal operations in the Transition Zone offshore Texas, from 2006 to 2009. Mr. Rhea holds a B.S.M.E. in Engineering from the University of Texas.
Rex H. White, Jr., age 80, is owner and principal of Rex H. White, Jr., Attorney at Law, a Board Certified Oil, Gas and Mineral Law attorney. Previously, Mr. White worked as a petroleum geologist/geophysicist for approximately 10 years. Mr. White holds a B.S. in Geology, an M.A. in Geology with a minor in Petroleum Engineering and an L.L.B. all from the University of Texas.
Involvement in Certain Legal Proceedings
Messrs. Cooke, Clifford, Smith and White were each directors of our company, and Messrs. Cooke and Clifford were officers of our company, at the time of our filing for protection under Chapter 11 of the U.S. Bankruptcy Code in March 2009. We exited bankruptcy with our assets and equity intact in May 2010.
Compensation Committee Interlocks and Insider Participation
The current members of our compensation committee are Messrs. White, Rhea and Smith. In 2012, none of our executive officers served as a director or member of the compensation committee of another entity, where an executive officer of the entity served as one of our directors or on our compensation committee.
Board Independence
On the basis of information solicited from each director, our board has affirmatively determined that each of Messrs. Rhea, White and Smith has no material relationship with the company and is independent within the meaning of our corporate governance guidelines, which comply with the applicable NYSE MKT listing standards and SEC rules. In making this determination, the board, with assistance from the company’s legal counsel, evaluated responses to a questionnaire completed annually by each director regarding relationships and possible conflicts of interest between each director, the company and management. In its review of director independence, the board considered all commercial, industrial, banking, consulting, legal, accounting, charitable, and familial relationships any director may have with the company or management.
79
EXECUTIVE COMPENSATION
Summary Executive Compensation Table
The table below summarizes the total compensation paid to or earned by our named executive officers for each of the three years ended December 31, 2012.
|
|
|
|
|
|
|
| Stock |
| Option |
|
| All Other |
|
| |||||||||||||
Name and Principal Position |
| Year |
| Salary |
| Bonus (1) |
| Awards |
| Awards(2) |
|
| Compensation(3) |
| Total | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas F. Cooke |
|
| 2012 |
|
| $ | 305,000 |
|
| $ | 37,438 |
|
| $ | — |
|
| $ | — |
|
|
| $ | 19,775 |
| $ | 362,213 |
|
Chairman of the Board and |
|
| 2011 |
|
|
| 305,000 |
|
|
| 175,000 |
|
|
| — |
|
|
| — |
|
|
|
| 8,333 |
|
| 488,333 |
|
Chief Executive Officer |
|
| 2010 |
|
|
| 258,125 |
|
|
| 55,000 |
|
|
| — |
|
|
| — |
|
|
|
| 8,333 |
|
| 321,458 |
|
Andrew C. Clifford |
|
| 2012 |
|
|
| 305,000 |
|
|
| 37,438 |
|
|
| — |
|
|
| — |
|
|
|
| 33,373 |
|
| 375,811 |
|
President |
|
| 2011 |
|
|
| 305,000 |
|
|
| 175,000 |
|
|
| — |
|
|
| — |
|
|
|
| 28,439 |
|
| 508,439 |
|
|
|
| 2010 |
|
|
| 258,125 |
|
|
| 55,000 |
|
|
| — |
|
|
| — |
|
|
|
| 20,916 |
|
| 334,041 |
|
Michael O. Aldridge (4) |
|
| 2012 |
|
|
| 250,000 |
|
|
| 24,550 |
|
|
| — |
|
|
| — |
|
|
|
| 10,000 |
|
| 284,550 |
|
Executive Vice President and |
|
| 2011 |
|
|
| 42,629 |
|
|
| — |
|
|
| — |
|
|
| 687,750 |
|
|
|
| 31,705 |
|
| 762,084 |
|
Chief Financial Officer |
|
| 2010 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
|
| — |
|
| — |
|
Brian Daigle |
|
| 2012 |
|
|
| 187,500 |
|
|
| 18,658 |
|
|
| — |
|
|
| — |
|
|
|
| 7,503 |
|
| 213,661 |
|
Vice President – Operations |
|
| 2011 |
|
|
| 180,000 |
|
|
| 25,000 |
|
|
| — |
|
|
| — |
|
|
|
| 8,420 |
|
| 213,420 |
|
|
|
| 2010 |
|
|
| 165,000 |
|
|
| — |
|
|
| — |
|
|
| 241,200 |
|
|
|
| 6,352 |
|
| 412,552 |
|
Randal McDonald (5) |
|
| 2012 |
|
|
| 160,000 |
|
|
| 11,784 |
|
|
| — |
|
|
| — |
|
|
|
| 6,400 |
|
| 178,184 |
|
Controller |
|
| 2011 |
|
|
| 15,179 |
|
|
| 1,300 |
|
|
| — |
|
|
| 138,600 |
|
|
|
| 585 |
|
| 155,664 |
|
|
|
| 2010 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
|
| — |
|
| — |
|
(1)
Bonuses include amounts attributable to a fiscal year even though paid after year end.
(2)
The amounts reported in the “Option Awards” Column reflect the grant date fair value of the options granted to the named executive officers in the year reflected, determined using the Black-Scholes option model. For information relating to the assumptions made by us in valuing the option awards made to our named executive officers in fiscal year 2012, refer to Note 11 of our financial statements for the year ended December 31, 2012.
(3)
All other compensation consists of:
Name |
|
| Year |
| Auto Allowance |
| 401k Plan Contribution |
| Moving Allowance | |||
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas F. Cooke |
|
| 2012 |
| $ | 19,775 |
| $ | — |
| $ | — |
|
|
| 2011 |
|
| 8,333 |
|
| — |
|
| — |
|
|
| 2010 |
|
| 8,333 |
|
| — |
|
| — |
Andrew C. Clifford |
|
| 2012 |
|
| 17,167 |
|
| 16,206 |
|
| — |
|
|
| 2011 |
|
| 8,333 |
|
| 20,106 |
|
| — |
|
|
| 2010 |
|
| 8,333 |
|
| 20,528 |
|
| — |
Michael O. Aldridge |
|
| 2012 |
|
| — |
|
| 10,000 |
|
| — |
|
|
| 2011 |
|
| — |
|
| 1,705 |
|
| 30,000 |
Brian Daigle |
|
| 2012 |
|
| — |
|
| 7,503 |
|
| — |
|
|
| 2011 |
|
| — |
|
| 8,420 |
|
| — |
|
|
| 2010 |
|
| — |
|
| 6,352 |
|
| — |
Randal McDonald |
|
| 2012 |
|
| — |
|
| 6,400 |
|
| — |
|
|
| 2011 |
|
| — |
|
| 585 |
|
| — |
(4)
Mr. Aldridge commenced employment as our Executive Vice President and Chief Financial Officer on October 31, 2011.
(5)
Mr. McDonald commenced employment as our Controller on November 28, 2011.
Narrative Discussion of Executive Compensation Table
Bonus Plan. Our board of directors has adopted an Annual Incentive Program which is intended to establish potential bonus payouts tied to satisfaction of performance criteria established by the board. Bonus payments during 2012 were performance based bonuses paid pursuant to the 2012 Annual Incentive Program.
Stock Options and Stock Awards. No stock awards or options were granted to named executive officers during 2012.
80
Outstanding Equity Awards at December 31, 2012
|
|
|
| Option Awards |
| Stock Awards | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| Equity Incentive |
| Equity Incentive | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| Plan Awards: |
| Plan Awards: | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| Number of |
| Market or Payout | ||||||||||||
|
|
|
| Number of |
| Number of |
|
|
|
|
| Unearned |
| Value of | ||||||||||||
|
|
|
| Securities |
| Securities |
|
|
|
|
| Shares, Units or |
| Unearned Shares, | ||||||||||||
|
|
|
| Underlying |
| Underlying |
| Option |
| Option |
| Other Rights |
| Units or Other | ||||||||||||
|
| Grant |
| Unexercised Options |
| Unexercised Options |
| Exercise |
| Expiration |
| That Have Not |
| Rights That Have | ||||||||||||
Name |
| Date |
| Exercisable |
| Unexercisable |
| Price |
| Date |
| Vested |
| Not Vested | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael Aldridge |
| 10/31/11 |
|
| 50,000 |
|
|
| 100,000 | (1) |
| $ | 4.585 |
|
|
| 10/31/18 |
|
|
| — |
|
| $ | — |
|
Brian Daigle |
| 07/01/10 |
|
| 26,667 |
|
|
| 13,333 | (1) |
|
| 1.530 |
|
|
| 07/01/20 |
|
|
| — |
|
|
| — |
|
|
| 04/14/10 |
|
| 60,000 |
|
|
| — |
|
|
| 3.000 |
|
|
| 04/14/20 |
|
|
| — |
|
|
| — |
|
Randal McDonald |
| 11/28/11 |
|
| 10,000 |
|
|
| 20,000 | (1) |
|
| 4.620 |
|
|
| 11/28/18 |
|
|
| — |
|
|
| — |
|
(1)
The stock options become exercisable in 1/3 annual increments on each of the first three anniversaries of the date of grant. The stock options will become immediately exercisable in their entirety in the event of certain changes in control.
Employment Agreements
In June 2013, our board of directors approved new employment agreements for our two principal officers, Thomas Cooke and Andy Clifford. Pursuant to the new employment agreements, (i) the annual base salary of Messrs. Cooke and Clifford was increased from its then current level of $305,000 by 4%, to $317,200, on July 1, 2013 and increases by 4% on July 1 of each succeeding year; (ii) the automobile allowance of Messrs. Cooke and Clifford was modified to either provide a company vehicle or pay a monthly automobile allowance, which allowance remains $700 per month for Mr. Clifford and was increased to $950 per month for Mr. Cooke; additionally, beyond repair and maintenance costs previously paid by the company, the automobile allowance has been revised to cover all costs of operating a vehicle; (iii) the expense reimbursement provisions were modified to clarify that the company will pay all incremental costs associated with maintenance of home offices by Messrs. Cooke and Clifford, including costs of internet service, telephone and facsimile service and, with respect to Mr. Clifford, a home workstation; (iv) travel pay in the amount of $200 per day was added for each overnight stay or out-of-town travel of twenty-four hours exclusively for business purposes; (v) Messrs. Cooke and Clifford each received options to purchase 250,000 shares of common stock exercisable at $3.00 per share for a term of five years and vesting on a quarterly basis over eight quarters; (vi) in the event of termination of employment due to death or disability, we will continue to pay base salary to the executive or his estate for a period of twelve months; and (vii) in the event of termination of employment by the company without cause or by the executive for “good reason”, we will pay a lump sum to the executive in an amount equal to two times the base salary and bonus paid during the twelve months immediately preceding termination and shall continue to provide health insurance for a period of twenty-four months.
Director Compensation
We use a combination of cash and equity-based incentive compensation to attract and retain qualified candidates to serve on our board. In setting director compensation, we consider the significant amount of time directors dedicate in fulfilling their duties as directors as well as the skill-level required by the company to be an effective member of our board. The form and amount of director compensation is reviewed by our compensation committee, which makes recommendations to the full board.
Effective November 2012, each non-employee director receives an annual fee of $10,000 and committee chairs receive an annual fee of $6,000 for the audit committee and $4,000 for all other committees, each of which fees is payable in two semi-annual installments. Prior to November 2012, each non-employee director received an annual fee of $6,000 and committee chairs received an annual fee of $4,000 for the audit committee and $2,000 for all other committees, each of which was payable in quarterly installments. Each non-employee director is reimbursed for reasonable out-of-pocket expenses incurred in attending such meetings. Additionally, upon initial appoint or election as a director and annually upon reelection as a director, non-employee directors are granted stock options to purchase 35,000 shares of our common stock at the then fair market value. Under our present director compensation program, option grants expire on the seventh anniversary of the grant date and vest 50% on the date of grant and 50% on the first anniversary of the date of grant.
81
The table below summarizes the total compensation paid to or earned by our non-management directors during 2012. The amounts included in the “Stock Awards” and “Option Awards” columns reflect the aggregate grant date fair value, and do not necessarily equate to the income that will ultimately be realized by the director for these awards.
|
| Fees Earned or Paid |
| Stock |
| Option |
| All Other |
|
| |||||
Name of Director |
| in Cash |
| Awards |
| Awards (1) |
| Compensation |
| Total | |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John W. Rhea, IV |
| $ | 13,000 |
| $ | — |
| $ | 231,700 |
| $ | — |
| $ | 244,700 |
Kevin M. Smith |
|
| 9,500 |
|
| — |
|
| 231,700 |
|
| — |
|
| 241,200 |
Rex H. White, Jr. |
|
| 13,000 |
|
| — |
|
| 231,700 |
|
| — |
|
| 244,700 |
(1)
Amounts reflect the aggregate grant date fair value of the option awards (options). The Black-Scholes option model was used to determine the grant date fair value of the options that we granted to the directors. For information relating to the assumptions made by us in valuing the option awards made to our non-management directors in fiscal year 2012, refer to Note 11 of our financial statements for the year ended December 31, 2012. On June 18, 2012, each non-management director serving at the time was granted options to purchase an aggregate 35,000 shares of our common stock. The options that were granted had a grant date fair value of $6.62 per option using the Black-Scholes option model.
As of December 31, 2012, each director had the following number of options outstanding: Mr. Rhea, 35,000; Mr. Smith, 130,000; and, Mr. White, 130,000.
82
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Unless otherwise indicated, the table below shows the amount of our common stock beneficially owned as of February 5, 2014, by (1) each person known to beneficially own more than 5% of our outstanding common stock, (2) each of our directors and named executive officers, and (3) all directors and executive officers as a group.
|
|
|
| Number of Shares |
| Total Number of |
|
| ||||||||
|
| Number of Shares |
| Subject to |
| Shares |
|
| ||||||||
|
| Not Subject to |
| Exercisable Warrants |
| Beneficially |
| Percent of | ||||||||
Name of Beneficial Owner |
| Options |
| and Options (1) |
| Owned (1) |
| Class (1)(2) | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas F. Cooke |
|
| 6,142,422 | (3) |
|
| 93,750 |
|
|
| 6,236,172 |
|
|
| 20.1 | % |
GSO Capital Partners (4) |
|
| 4,800,000 |
|
|
| — |
|
|
| 4,800,000 |
|
|
| 15.5 | % |
Macquarie Americas Corp. (5) |
|
| 3,300,000 |
|
|
| — |
|
|
| 3,300,000 |
|
|
| 10.7 | % |
Andrew C. Clifford |
|
| 2,637,164 | (6) |
|
| 93,750 |
|
|
| 2,730,914 |
|
|
| 8.8 | % |
Brian Daigle |
|
| 60,000 |
|
|
| 100,000 |
|
|
| 160,000 |
|
|
| * |
|
John W. Rhea, IV |
|
| — |
|
|
| 52,500 |
|
|
| 52,500 |
|
|
| * |
|
Kevin M. Smith |
|
| 195,473 | (7) |
|
| 137,500 |
|
|
| 332,973 |
|
|
| 1.1 | % |
Rex H. White, Jr. |
|
| 52,500 |
|
|
| 137,500 |
|
|
| 190,000 |
|
|
| * |
|
Randal McDonald |
|
| — |
|
|
| 20,000 |
|
|
| 20,000 |
|
|
| * |
|
John Ebert |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Directors and executive officers as a group (8 persons) (3) (6) (7) (8) |
|
| 9,087,559 |
|
|
| 635,000 |
|
|
| 9,722,559 |
|
|
| 30.8 | % |
*
Ownership is less than 1%.
(1)
Reflects our common stock that could be acquired within sixty days of the record date upon the exercise of outstanding warrants and options.
(2)
Based on 30,946,601 shares of our common stock outstanding as of February 5, 2014.
(3)
Includes 104,148 shares held by Mr. Cooke’s spouse, as to which he disclaims beneficial ownership.
(4)
Address is 345 Park Avenue, New York, NY 10154. Based on a Schedule 13G, Amendment No. 1, filed with the SEC on February 14, 2013. Blackstone/GSO Capital Solutions Fund L.P. and Blackstone/GSO Capital Solutions Overseas Master Fund L.P. (collectively, the “GSO Funds”) respectively hold 3,578,781 and 1,221,219 shares of our common stock. Blackstone/GSO Capital Solutions Associates LLC is the general partner of Blackstone/GSO Capital Solutions Fund LP. GSO Holdings I LLC is the managing member of Blackstone/GSO Capital Solutions Associates LLC. GSO Capital Partners LP is the investment manager of Blackstone/GSO Capital Solutions Overseas Master Fund L.P., and in that respect holds discretionary investment authority for, and may be deemed to be the beneficial owner of the shares held by, Blackstone/GSO Capital Solutions Overseas Master Fund L.P. GSO Advisor Holdings L.L.C. is the general partner of GSO Capital Partners LP. Blackstone Holdings I L.P. is the sole member of each of GSO Holdings I LLC and GSO Advisor Holdings L.L.C. Blackstone Holdings I/II GP Inc. is the general partner of Blackstone Holdings I L.P. The Blackstone Group L.P. is the controlling shareholder of Blackstone Holdings I/II GP Inc. Blackstone Group Management L.L.C. is the general partner of The Blackstone Group L.P. Stephen A. Schwarzman is the founding member of Blackstone Group Management L.L.C. In addition, each of Bennett J. Goodman, J. Albert Smith III and Douglas I. Ostrover, each of whom serves as an executive of GSO Holdings I LLC, which is an affiliate of Blackstone/GSO Capital Solutions Associates LLC, may have shared investment control with respect to the common stock held by the GSO Funds.
(5)
Address is 125 W. 55th Street, 22nd Floor, New York, NY. Based on a Schedule 13D filed with the SEC on July 24, 2008 by Macquarie Americas Corp.
(6)
Includes (a) 2,500,000 shares held by held by CPK Resources, LLC of which Mr. Clifford is the principal officer and owner, (b) 5,886 shares held by Mr. Clifford’s SEP-IRA, and (c) 4,173 shares held by the SEP-IRA of Mr. Clifford’s spouse, as to which he disclaims beneficial ownership.
(7)
Includes 20,000 shares held by Mr. Smith’s spouse, as to which he disclaims beneficial ownership.
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DESCRIPTION OF THE EXCHANGE NOTES
The exchange notes will be issued, and the outstanding notes were issued, under an indenture (the “Indenture”) dated as of November 22, 2013, as amended or supplemented from time to time, among the Company, all of the Company’s existing direct and indirect wholly-owned Domestic Subsidiaries, as guarantors (the “Guarantors”) and The Bank of New York Mellon Trust Company, N.A., as trustee (in such capacity, the “Trustee”) and as collateral agent (in such capacity, the “Collateral Agent”). The terms of the notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act” or “TIA”).
The following description is a summary of the material terms and provisions of the notes, the Indenture, the Security Documents and the Intercreditor Agreement. It does not purport to be a complete description of the notes or such agreements and is subject to the detailed provisions of, and qualified in its entirety by reference to, the notes, the Indenture, the Security Documents and the Intercreditor Agreement. We urge you to read the Indenture, the notes, the Security Documents and the Intercreditor Agreement because they, and not this description, define your rights as holders of the notes.
You can find the definitions of certain terms used in this description under the subheading “— Certain Definitions.” In this description, the words “Issuer,” “we,” “us,” and “our” refer only to Saratoga Resources, Inc. and not to any of its subsidiaries, and that term “Guarantor” refers to each Domestic Subsidiary that guarantees the notes, so long as it guarantees the notes. The term “notes” refers to both the outstanding notes issued on November 22, 2013 and the exchange notes, unless the context otherwise requires.
If the exchange offer is consummated, the exchange notes and the outstanding notes will together constitute a single series of debt securities under the Indenture. Holders of outstanding notes who do not exchange their outstanding notes for exchange notes will vote together with the Holders of the exchange notes for all relevant purposes under the Indenture. In that regard, the Indenture requires that certain actions by the Holders under the Indenture (including acceleration after an Event of Default) must be taken, and certain rights must be exercised, by specified minimum percentages of the aggregate principal amount of all outstanding notes issued under the Indenture. In determining whether Holders of the requisite percentage in principal amount have given any notice, consent or waiver or taken any other action permitted under the Indenture, any unexchanged outstanding notes that remain outstanding after the exchange offer will be aggregated with the exchange notes, and the Holders of these outstanding notes and exchange notes will vote together as a single series for all such purposes. Accordingly, all references in this section of the prospectus to specified percentages in aggregate principal amount of the outstanding notes mean, at any time after the exchange offer is consummated, such percentage in aggregate principal amount of the outstanding notes and the exchange notes.
The registered Holder of a note will be treated as the owner of it for all purposes. Only registered Holders will have rights under the Indenture.
Brief Description of the Notes and the Note Guarantees
The Notes
The notes will:
| • |
| be the general senior obligations of the Issuer; |
| • |
| rank equal in right of payment with all of the Issuer’s existing and future senior indebtedness; |
| • |
| be effectively senior to all of the Issuer’s existing and future unsecured indebtedness to the extent of the value of the Collateral securing the notes; |
| • |
| be effectively secured on a first-priority basis by Liens on the Collateral described herein, subject to Permitted Liens; |
| • |
| be structurally subordinated to all existing and future indebtedness and other liabilities of the Issuer’s subsidiaries that do not guarantee the notes; and |
| • |
| be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each Guarantor as set forth herein. |
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The Note Guarantees
The notes will be guaranteed fully and unconditionally, jointly and severally, by all of the Issuer’s existing and future Domestic Subsidiaries.
Each guarantee of the notes will:
| • |
| be a general senior obligation of each Guarantor; |
| • |
| rank equal in right of payment with all of such Guarantor’s existing and future senior indebtedness; |
| • |
| be effectively secured on a first-priority basis by Liens on the Collateral described herein, subject to Permitted Liens; |
| • |
| be effectively senior to all of such Guarantor’s existing and future unsecured indebtedness to the extent of the value of the Collateral securing such guarantee; and |
| • |
| be structurally subordinated to all existing and future indebtedness and other liabilities of such Guarantor’s subsidiaries that do not guarantee the notes. |
As of the date hereof, all of our Subsidiaries will be “Restricted Subsidiaries.” However, under the circumstances described below under the caption “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries,” we will be permitted to designate certain of our Subsidiaries as “Unrestricted Subsidiaries.” Our Unrestricted Subsidiaries will not be subject to the restrictive covenants in the Indenture and will not guarantee the notes.
Principal, Maturity and Interest
The Issuer issued the outstanding notes in an initial maximum aggregate principal amount of $54.6 million. The Issuer may issue additional notes under the Indenture from time to time. Any issuance of additional notes is subject to all of the covenants in the Indenture, including the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock.” The notes and any additional notes subsequently issued under the Indenture will be treated as a single class for all purposes under the Indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase, the Security Documents, the registration rights agreement and the Intercreditor Agreement. Unless the context requires otherwise, references to “notes” for all purposes of the Indenture and this “Description of Notes” include any additional notes that are actually issued under the Indenture. The Issuer will issue notes in denominations of $2,000 and integral multiples of $1,000 in excess thereof. The notes will mature on December 31, 2015.
Interest on the notes will accrue at the rate of 10.0% per annum and will be payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year, commencing on December 31, 2013. Interest on overdue principal and interest, including Additional Interest, if any, will accrue at a rate that is 2% higher than the then applicable interest rate on the notes. The Issuer will make each interest payment to the holders of record on the immediately preceding March 15, June 15, September 15 and December 15, respectively.
Interest on the notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.
Additional Interest may accrue and be payable under the circumstances set forth in “—Exchange Offer; Registration Rights.”
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Methods of Receiving Payments on the Notes
If a holder of notes has given wire transfer instructions to the Issuer, the Issuer will pay all principal, interest and premium and Additional Interest, if any, on that holder’s notes in accordance with those instructions. All other payments on the notes will be made at the office or agency of the paying agent and registrar unless the Issuer elects to make interest payments by check mailed to the noteholders at their respective addresses set forth in the register of holders; provided that all payments of principal of, and interest and premium with respect to, the notes represented by one or more global notes registered in the name of, or held by, DTC or its nominee will be made by wire transfer of immediately available funds to the accounts specified by the holder or holders thereof.
Paying Agent and Registrar for the Notes
The Trustee will initially act as paying agent and registrar. The Issuer may change the paying agent or registrar without prior notice to the holders of the notes, and the Issuer or any of its Subsidiaries may act as paying agent or registrar.
Transfer and Exchange
A holder may transfer or exchange notes in accordance with the provisions of the Indenture. The registrar and the Trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. The Issuer will be required to pay all taxes due on transfer. The Issuer will not be required to transfer or exchange any note selected for redemption. In addition, the Issuer will not be required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed.
Note Guarantees
The notes will be guaranteed by each of the Issuer’s current and future Domestic Subsidiaries. These Note Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee will be limited as necessary to prevent that Note Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors—Risks Related to the Notes—Federal, state and foreign fraudulent transfer laws may permit a court to avoid the notes and the guarantees, subordinate claims in respect of the notes and the guarantees and require noteholders to return payments received. If this occurs, noteholders may not receive any payments on the notes.” In the event of a bankruptcy, liquidation or reorganization of any of the non-Guarantor Subsidiaries, these non-Guarantor Subsidiaries will pay the holders of their liabilities, including their debt and trade payables, and preferred stock before they will be able to distribute any of their assets to us. As of the Issue Date, all of our Subsidiaries will be “Restricted Subsidiaries.”
A Guarantor may not sell or otherwise dispose of all or substantially all of its assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person) another Person, other than the Issuer or another Guarantor, unless:
(1)
immediately after giving effect to that transaction, no Default or Event of Default exists; and
(2)
either:
(a)
the Person acquiring the property in any such sale or disposition or the Person formed by or surviving any such consolidation or merger assumes all the obligations of that Guarantor under the Indenture and its Note Guarantee pursuant to a supplemental indenture, the registration rights agreement and the Intercreditor Agreement and the other Security Documents, each satisfactory to the Trustee; or
(b)
the Net Proceeds of such sale or other disposition are applied in accordance with the applicable provisions of the Indenture.
The Note Guarantee of a Guarantor will be released:
(1)
in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) the Issuer or a Restricted Subsidiary of the Issuer, if the sale or other disposition does not violate the “Asset Sale” provisions of the Indenture;
(2)
in connection with any sale, transfer or other disposition of all of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) the Issuer or a Restricted Subsidiary of the Issuer, if the sale, transfer or other disposition does not violate the “Asset Sale” provisions of the Indenture;
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(3)
if the Issuer designates any Restricted Subsidiary that is a Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the Indenture; or
(4)
upon legal defeasance or satisfaction and discharge of the Indenture as provided below under the captions “—Legal Defeasance and Covenant Defeasance” and “—Satisfaction and Discharge.”
See “—Repurchase at the Option of Holders—Asset Sales.”
Under the circumstances described below under the caption “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries,” the Issuer will be permitted to designate certain of its Subsidiaries as “Unrestricted Subsidiaries.” The effect of designating a Subsidiary as an “Unrestricted Subsidiary” will be:
| • |
| the Unrestricted Subsidiary will not be subject to most of the restrictive covenants in the Indenture; |
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| a Subsidiary that has previously been a Guarantor and that is designated as an “Unrestricted Subsidiary” will be released from its Note Guarantee; and |
| • |
| the assets, income, cash flow and other financial results of the Unrestricted Subsidiary will not be consolidated with those of the Issuer for purposes of calculating compliance with the restrictive covenants contained in the Indenture. |
Security
Pursuant to the Security Documents entered into by the Issuer, the Guarantors and the Collateral Agent for the benefit of the Collateral Agent, the Trustee and the holders of notes, the notes, the Note Guarantees and all other Obligations under the Indenture are secured by a Lien on substantially all of the Issuer’s and the Guarantors’ existing and future tangible and intangible assets (other than Excluded Assets), including (without limitation):
(1)
accounts receivables;
(2)
equipment, goods, inventory and fixtures;
(3)
documents, instruments and chattel paper;
(4)
letter-of-credit rights;
(5)
securities collateral;
(6)
investment property (as defined in the UCC), including all Capital Stock of the Issuer’s Subsidiaries;
(7)
copyrights and trademarks;
(8)
commercial tort claims;
(9)
general intangibles;
(10)
deposit accounts;
(11)
cash;
(12)
supporting obligations;
(13)
books and records;
(14)
real property;
(15)
As-Extracted Collateral;
(16)
Oil and Gas Properties;
(17)
to the extent not covered by clauses (1) through (16) above, all other personal property of the Issuer and each Guarantor, whether tangible or intangible;
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(18)
proceeds and products of each of the foregoing and all accessions to, substitutions and replacements for each of the foregoing, and any and all proceeds of any insurance, indemnity, warranty or guaranty payable to the Issuer or any Guarantor from time to time with respect to any of the foregoing; and
(19)
all other existing and future tangible and intangible assets that from time to time become subject to a Lien securing First Lien Obligations or Second Lien Obligations.
Clauses (1) through (19) above are herein collectively referred to as “Collateral” (to the extent such assets do not constitute Excluded Assets).
The Issuer shall cause each applicable Restricted Subsidiary to, at their sole cost and expense, (i) execute and deliver all such agreements and instruments as necessary (or as the Collateral Agent may reasonably request) to more fully or accurately describe the property intended to be Collateral or the obligations intended to be secured by the Security Documents and (ii) file any such notice filings or other agreements or instruments as may be reasonably necessary or desirable under applicable law to perfect the Liens created by the Security Documents at such times and at such places as are necessary (or as the Collateral Agent may reasonably request), in each case subject to the terms of the Security Documents and the First Lien Security Documents, including any waivers thereunder by the First Lien Agent. Certain security interests in the Collateral may not be in place on the Issue Date or may not be perfected on the Issue Date. See “—Certain Covenants—Post-Closing.”
Notwithstanding the foregoing, the Collateral will not include any of the following assets (collectively, the “Excluded Assets”):
(1)
any asset or property right of the Issuer or any Guarantor of any nature:
(a)
if the grant of a security interest shall constitute or result in (i) the abandonment, invalidation or unenforceability of such asset or property right or the Issuer’s or any Guarantor’s loss of use of such asset or property right or (ii) a breach, termination or default under any lease, license, contract or agreement (other than to the extent that any such term would be rendered ineffective pursuant to Sections 9-406, 9-407, 9-408 or 9-409 of the UCC (or any successor provision or provisions) of any relevant jurisdiction or any other applicable law (including the United States Bankruptcy Code) or principles of equity) to which the Issuer or such Guarantor is party; and
(b)
to the extent that any applicable law or regulation prohibits the creation of a security interest thereon (other than to the extent that any such term would be rendered ineffective pursuant to any applicable law or principles of equity);
provided, however, that such lease, license, contract, property rights or other agreement will cease to be an Excluded Asset immediately and automatically at such time as the condition causing such abandonment, invalidation or unenforceability is remedied and, to the extent severable, any portion of such lease, license, contract, property rights or other agreement that does not result in any of the consequences specified in clauses (a) and (b) in this clause (1) will not be an Excluded Asset; provided further that the Issuer shall, and shall cause each Restricted Subsidiary to, make all commercially reasonable efforts to prevent any asset or property, including but not limited to Permitted Business Investments, from constituting Excluded Assets;
(2)
Voting Stock of any Foreign Subsidiary (to the extent such Foreign Subsidiary is a “controlled foreign corporation” for U.S. federal income tax purposes) that is directly owned by the Issuer or any Guarantor, solely to the extent representing in excess of 65% of the total voting power of all outstanding Voting Stock of such Foreign Subsidiary and all Capital Stock of Foreign Subsidiaries not directly owned by any Person that is the Issuer or a Guarantor;
(3)
any foreign intellectual property;
(4)
any applications for trademarks or service marks filed in the United States Patent and Trademark Office pursuant to 15 U.S.C. § 1051 Section 1(b) unless and until evidence of use of the mark in interstate commerce is submitted to the PTO pursuant to 15 U.S.C. § 1051 Section 1(c) or Section 1(d);
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(5)
(i) deposit and securities accounts the balance of which consists exclusively of (a) withheld income taxes and federal, state or local employment taxes in such amounts as are required to be paid to the Internal Revenue Service or state or local government agencies within the following two months with respect to employees of the Issuer or any Guarantor, and (b) amounts required to be paid over to an employee benefit plan pursuant to DOL Reg. Sec. 2510.3-102 on behalf of or for the benefit of employees of the Issuer or any Guarantor, and (ii) all segregated deposit accounts constituting (and the balance of which consists solely of funds set aside in connection with) tax accounts, payroll accounts and trust accounts;
(6)
fixed or capital assets owned by the Issuer or any Guarantor that is subject to a capital lease or purchase money obligations, in each case permitted to be incurred pursuant to the covenants described below under the captions “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” and “—Certain Covenants—Liens” if the contract or other agreement in which such Lien is granted prohibits the creation of any other Lien on such fixed or capital assets, but only for so long as such prohibition is in effect and only with respect to the portion of such fixed or capital assets as to which such other Lien attaches and such prohibition applies; and
(7)
de minimus or immaterial assets for which perfection of the security could not be obtained without unreasonable cost and expense or under applicable law.
Intercreditor Agreement
In connection with the issuance of the notes, we entered into an Intercreditor Agreement among the First Lien Agent, on behalf of the First Lien Creditors (including the holders of the notes), the Second Lien Agent, on behalf of the Second Lien Creditors, the Issuer and the Guarantors, which will, among other things, define the relative rights of the First Lien Agent and the First Lien Creditors and the Second Lien Agent and the Second Lien Creditors and related matters with respect to the Collateral. By purchasing notes, each holder is deemed to have authorized the First Lien Agent to enter into the Intercreditor Agreement and each holder shall be bound by the terms of the Intercreditor Agreement.
Relative Lien Priorities; Notes Effectively Senior to Second Lien Obligations
The Intercreditor Agreement provides that, notwithstanding the date, manner or order of grant, attachment or perfection of any Liens on Collateral securing the Obligations arising under the Indenture together with all other First Lien Obligations (“First Priority Liens”) or any Liens thereon that secure the Second Lien Obligations (“Second Priority Liens”), and notwithstanding any provision of the Uniform Commercial Code of any applicable jurisdiction or any other applicable law or the provisions of any First Lien Document or Second Lien Document or any other circumstance whatsoever, each of the First Lien Agent, on behalf of the First Lien Creditors, and the Second Lien Agent, on behalf of the Second Lien Creditors, will agree that (a) any First Priority Liens then or thereafter held by or for the benefit of any First Lien Creditor will be senior in right, priority, operation, effect and all other respects to any and all Second Priority Liens and (b) any Second Priority Liens then or thereafter held by or for the benefit of any Second Lien Creditor will be junior and subordinate in right, priority, perfection, operation, effect and all other respects to any and all First Priority Liens, and the First Priority Liens will be and remain senior in right, priority, perfection, operation, effect and all other respects to any Second Priority Liens for all purposes.
As a result of the foregoing, the Second Lien Obligations will be effectively subordinated to the First Lien Obligations to the extent of the value of the Collateral.
No Payment Subordination to First Lien Obligations
The Intercreditor Agreement provides that the subordination of Liens securing the Second Lien Obligations described herein affects only the relative priority of those Liens, and does not subordinate the Second Lien Obligations in right of payment to the First Lien Obligations. Nothing in the Intercreditor Agreement affects the entitlement of any Second Lien Creditor to receive and retain required payments of interest, principal, and other amounts in respect of the Second Lien Obligations unless the receipt is expressly prohibited by, or results from the Second Lien Creditor’s breach of, the Intercreditor Agreement.
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Prohibition on Contesting Liens; Additional Collateral
The Intercreditor Agreement provides that (a) each of the First Lien Agent, on behalf of the First Lien Creditors, and the Second Lien Agent, on behalf of the Second Lien Creditors, will not, and will waive any right to, contest or support any other Person in contesting, in any proceeding (including any insolvency or liquidation proceeding), the priority, validity, extent, perfection or enforceability of any First Priority Lien or any Second Priority Lien, as the case may be; provided that nothing in the Intercreditor Agreement will be construed to prevent or impair the rights of the First Lien Creditors or the Second Lien Creditors to enforce the Intercreditor Agreement to the extent provided thereby, including the provisions relating to the priority of Liens securing the First Lien Obligations and (b) if the Issuer or any Guarantor creates any additional Liens upon any property to secure (i) any First Lien Obligations, it must substantially concurrently grant a Lien upon such property as security for the Second Lien Obligations and (ii) the Second Lien Obligations, it must substantially concurrently grant a Lien upon such property as security for the First Lien Obligations. Subject to clauses (a) and (b) above, if a Second Lien Creditor hereafter acquires a Lien on property to secure a Second Lien Obligation where the property is not also subject to a Lien securing the First Lien Obligations, then such Second Lien Creditor will give First Lien Agent written notice of such Lien no later than five Business Days after acquiring such Lien. If First Lien Agent also obtains a Lien on such property or if such Second Lien Creditor fails to provide such timely notice to First Lien Agent, then such property will be deemed to be Collateral for all purposes thereunder. If the Second Lien Agent or any Second Lien Creditor shall acquire any Lien on any property of the Issuer or any Guarantor or any of their respective Subsidiaries securing any Second Lien Obligations which property are not also subject to the Lien of the First Lien Agent under the First Lien Collateral Documents, then the Second Lien Agent (or the relevant Second Lien Creditor), shall, without the need for any further consent of any other Person and notwithstanding anything to the contrary in any other Second Lien Loan Document (x) hold and be deemed to have held such Lien and security interest for the benefit of the First Lien Agent as security for the First Lien Obligations, or (y) release such Lien. The Second Lien Agent on behalf of the Second Lien Creditors will agree that, to the extent that the provisions in clause (b) above are not complied with for any reason, without limiting any other rights and remedies available to First Lien Agent or First Lien Creditors, any amounts received by or distributed to any of them pursuant to or as a result of Liens granted in contravention of this clause (b) will be subject to the “Payment Over” provisions described below.
Exercise of Rights and Remedies; Standstill
The Intercreditor Agreement provides that the First Lien Agent and the other First Lien Creditors will, at all times prior to the Discharge of First Lien Priority Obligations, have the exclusive right to enforce rights and exercise remedies (including any right of setoff) with respect to the Collateral (including making determinations regarding the release, disposition or restrictions with respect to the Collateral), or to commence or seek to commence any action or proceeding with respect to such rights or remedies (including any foreclosure action or proceeding or any insolvency or liquidation proceeding), all in such order and in such manner as they may determine in the exercise of their sole discretion, in each case, without any consultation with or the consent of the Second Lien Agent or any other Second Lien Creditor, and no Second Lien Creditor will have any such right; provided, however, that after a period of 180 days following notice from the Second Lien Agent to the First Lien Agent that a Second Lien Actionable Default has occurred, so long as the First Lien Agent is not diligently pursuing in good faith an enforcement action with respect to all or a material portion of the Collateral or diligently attempting to vacate any stay or prohibition against such exercise, the Second Lien Creditors may enforce or exercise any rights or remedies with respect to any Collateral (the “Standstill Period”).
The Intercreditor Agreement also provides that no Second Lien Creditor will (x) contest, protest, or object to any exercise of remedies by the First Lien Agent or any First Lien Creditor nor have any right to direct the First Lien Agent to exercise remedies or take any other action under the First Lien Documents; or (y) object to (and waive any and all claims with respect to) the forbearance by the First Lien Agent or First Lien Creditors from exercising any remedies. Notwithstanding the foregoing, the First Lien Agent’s right to act as provided for in the foregoing shall terminate if any insolvency proceeding has been commenced.
The Intercreditor Agreement will further provide that notwithstanding the foregoing, a Second Lien Creditor may,
(a)
if an insolvency proceeding has been commenced by or against the Issuer or any Guarantor, file a claim or statement of interest with respect to the Second Lien Obligations;
(b)
take any action (not adverse to the priority status of the Liens on the Collateral securing the First Lien Obligations, or the rights of the First Lien Agent or any First Lien Creditors to exercise any remedies) in order to create, preserve, protect or perfect its Lien in and to the Collateral;
(c)
file any necessary responsive or defensive pleadings in opposition to any motion, claim, adversary proceeding, or other pleading made by any person objecting to or otherwise seeking the disallowance of the claims of Second Lien Creditors, including any claims secured by the Collateral, if any, in each case in accordance with the terms of the Intercreditor Agreement;
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(d)
vote on any plan of reorganization as more particularly described below;
(e)
exercise rights and remedies as unsecured creditors as more particularly described below;
(f)
join (but not exercise any control with respect to) any judicial foreclosure proceeding or other judicial lien enforcement proceeding with respect to the Collateral initiated by the First Lien Agent to the extent that any such action could not reasonably be expected, in any material respect, to restrain, hinder, limit, delay for any material period or otherwise interfere with the exercise of remedies by the First Lien Agent (it being understood that neither the Second Lien Agent nor any Second Lien Creditor will be entitled to receive any proceeds thereof unless otherwise expressly permitted in the Intercreditor Agreement); and
(g)
exercise any remedies after the termination of the Standstill Period if and to the extent permitted above.
Insolvency and Liquidation Proceedings
The Intercreditor Agreement provides that:
(a)
If the Issuer or any Guarantor is subject to any insolvency proceeding and the First Lien Agent consents to the use of cash collateral (as such term is defined in Section 363(a) of the United States Bankruptcy Code, “Cash Collateral”), on which the First Lien Agent has a Lien or permits the Issuer or any Guarantor to obtain financing provided by any one or more First Lien Creditors under Section 364 of the United States Bankruptcy Code (such financing, a “DIP Financing”), then the Second Lien Agent agrees that it will, on behalf of the Second Lien Creditors, consent to such Cash Collateral use (and not control, protest or object to such Cash Collateral use) and raise no objection to (or protest or contest) such DIP Financing and, to the extent the Liens securing the First Lien Obligations are discharged, subordinated to, or pari passu with such DIP Financing, Second Lien Agent will subordinate its Liens in the Collateral to the Liens securing such DIP Financing; provided that (i) the principal amount of any such DIP Financing plus the outstanding principal amount of other First Lien Obligations does not exceed the First Lien Cap and (ii) any such Cash Collateral use or DIP Financing does not compel the Issuer or any Guarantor to seek confirmation of a specific plan of reorganization for which all or substantially all of the material terms are set forth in the Cash Collateral order or DIP Financing documentation. If First Lien Creditors offer to provide DIP Financing that meets the requirements set forth in clauses (i) through (iv) above, the Second Lien Agent will not have the right to, directly or indirectly, provide, offer to provide, or support any DIP Financing secured by a Lien senior to or pari passu with the Liens securing the First Lien Priority Obligations. If, in connection with any Cash Collateral use or DIP Financing, any Liens on the Collateral held by First Lien Creditors are subject to a surcharge or are subordinated to an administrative priority claim, a professional fee “carve out,” or fees owed to the United States Trustee, and so long as the amount of such surcharge, claim, carve out, or fees is reasonable under the circumstances, then the Liens on the Collateral of Second Lien Creditors will also be subordinated to such interest or claim and will remain subordinated to the Liens on the Collateral of First Lien Creditors consistent with the Intercreditor Agreement.
(b)
The Second Lien Agent will consent, and will not object or oppose a motion to dispose of any Collateral free and clear of the Liens or other claims in favor of the Second Lien Agent under Section 363 of the United States Bankruptcy Code if the requisite First Lien Creditors under the First Lien Documents have consented to such disposition of such assets, and such motion does not impair, subject to the priorities set forth in the Intercreditor Agreement, the rights of Second Lien Creditors under Section 363(k) of the United States Bankruptcy Code (so long as the right of the Second Lien Creditors to offset their claim against the purchase price is only after the First Lien Priority Obligations have been paid in full in cash).
(c)
Until the Discharge of First Lien Priority Obligations, the Second Lien Agent will agree not to (a) seek (or support any other person seeking) relief from the automatic stay or any other stay in any insolvency proceeding in respect of the Collateral, without the prior written consent of the First Lien Agent, oppose any request by the First Lien Agent or any First Lien Creditor to seek relief from the automatic stay or any other stay in any insolvency proceeding in respect of the Collateral.
(d)
In any insolvency proceeding involving the Issuer or any Guarantor, no Second Lien Creditor will contest, protest or object (or support any other person contesting):
(i)
any request by the First Lien Agent or other First Lien Creditors for adequate protection; or
(ii)
any objection by the First Lien Agent or First Lien Creditors to any motion, relief, action, or proceeding based on the First Lien Agent or First Lien Creditors claiming a lack of adequate protection.
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(e)
In any insolvency proceeding involving the Issuer or any Guarantor:
(i)
if any one or more First Lien Creditors are granted adequate protection in the form of a replacement Lien (on existing or future assets of the Issuer or any Guarantor) in connection with any DIP Financing or use of Cash Collateral, then the Second Lien Agent will also be entitled to seek, without objection from First Lien Creditors, adequate protection in the form of a replacement Lien (on such existing or future assets of the Issuer or any Guarantor), which replacement Lien, if obtained, will be subordinate to the Liens securing the First Lien Obligations (including those under a DIP Financing) on the same basis as the other Liens securing the Second Lien Obligations are subordinate to the First Lien Obligations under the Intercreditor Agreement;
(ii)
if any one or more Second Lien Creditors are granted adequate protection in the form of a replacement Lien (on existing or future assets of the Issuer or any Guarantor), then the First Lien Agent will also be entitled to seek, without objection from Second Lien Creditors, a senior adequate protection Lien on existing or future assets of the Issuer or any Guarantor as security for the First Lien Obligations and that any adequate protection Lien on such existing or future assets securing the Second Lien Obligations will be subordinated to the Lien on such assets securing the First Lien Obligations on the same basis as the other Liens securing the Second Lien Obligations are subordinated to the First Lien Obligations under the Intercreditor Agreement;
(iii)
if any one or more First Lien Creditors are granted adequate protection in the form of an expense of administration claim in connection with any DIP Financing or use of Cash Collateral, then the Second Lien Agent will also be entitled to seek, without objection from First Lien Creditors, adequate protection in the form of an expense of administration claim, which administration claim, if obtained, will be subordinate to the administration claim of the First Lien Creditors; and
(iv)
if any one or more Second Lien Creditors are granted adequate protection in the form of an expense of administration claim in connection with any DIP Financing or use of Cash Collateral, then First Lien Agent will also be entitled to seek, without objection from Second Lien Creditors, adequate protection in the form of an expense of administration claim, which administration claim, if obtained, will be senior to the administration claim of the Second Lien Creditors.
(f)
Neither the Second Lien Agent nor any other Second Lien Creditor will object to, oppose, or challenge any claim by the First Lien Agent or any First Lien Creditor for allowance in any insolvency proceeding of First Lien Obligations consisting of post-petition interest, fees, or expenses.
(g)
Neither the First Lien Agent nor any other First Lien Creditor will object to, oppose, or challenge any claim by the Second Lien Agent or any Second Lien Creditor for allowance in any insolvency proceeding of Second Lien Obligations consisting of post-petition interest, fees, or expenses.
Payment Waterfall
The Intercreditor Agreement will provide that any Collateral or proceeds thereof received by any of the First Lien Creditors or the Second Lien Creditors in connection with any disposition of, or collection on, such Collateral upon the enforcement or exercise of any right or remedy (including any right of setoff) will be applied as follows:
first, to the payment of costs and expenses of the First Lien Agent in accordance with the First Lien Documents or the Second Lien Agent in accordance with the Second Lien Documents, as the case may be, in connection with such enforcement or exercise (to the extent not prohibited under the terms of the Intercreditor Agreement);
second, to the payment in full in cash or cash collateralization of the First Lien Priority Obligations in accordance with the First Lien Documents, and in the case of payment of any revolving loans, together with the concurrent permanent reduction of any revolving loan commitment thereunder in an amount equal to the amount of such payment;
third, upon and following the Discharge of First Lien Priority Obligations, to the payment in full in cash of the Second Lien Priority Obligations in accordance with the Second Lien Documents;
fourth, to the payment in full in cash of the Excess First Lien Obligations in accordance with the First Lien Documents;
fifth, to the payment in full in cash of the Excess Second Lien Obligations in accordance with the Second Lien Documents; and
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sixth, any surplus Collateral or proceeds then remaining will be returned to the Issuer, the applicable Guarantor or to whomsoever may be lawfully entitled to receive the same or as a court of competent jurisdiction may direct.
Payment Over
The Intercreditor Agreement provides that so long as the Discharge of First Lien Priority Obligations has not occurred, any Collateral or any proceeds thereof received by the Second Lien Agent or any other Second Lien Creditor in violation of the Intercreditor Agreement with respect to the Collateral, or otherwise, will be segregated and held in trust and either retained or forthwith transferred or paid over to the First Lien Agent for the benefit of the First Lien Creditors in the same form as received, together with any necessary endorsements.
Certain Voting Matters
The Intercreditor Agreement provides that the Second Lien Creditors may not vote on any plan of reorganization (including, without limitation, the right to vote to accept or reject any plan of partial or complete liquidation, reorganization, arrangement, composition or extension) to the extent inconsistent with the terms of the Intercreditor Agreement.
Postponement of Subrogation
The Intercreditor Agreement provides that no payment or distribution to any First Lien Creditor pursuant to the provisions of the Intercreditor Agreement will entitle any Second Lien Creditor to exercise any rights of subrogation in respect thereof until the Discharge of First Lien Priority Obligations will have occurred.
Unsecured Creditor Remedies
The Intercreditor Agreement provides that, subject to the terms and provisions thereof, the Second Lien Agent and the other Second Lien Creditors may, in accordance with the Second Lien Documents and applicable law, exercise any rights and exercise remedies against the Issuer and the Guarantors that could be exercised as an unsecured creditor. Notwithstanding the above, in the event that any Second Lien Creditor becomes a judgment Lien creditor in respect of Collateral as a result of its enforcement of its rights as an unsecured creditor, such judgment Lien will be subject to the terms of the Intercreditor Agreement for all purposes (including in relation to the First Priority Liens and the First Lien Obligations) to the same extent as all other Liens securing the Second Lien Obligations are subject to the Intercreditor Agreement.
Purchase Option
The Intercreditor Agreement provides that within 60 days of the occurrence (and during the continuation) of (i) the acceleration of any First Lien Priority Obligations, (ii) the First Lien Agent’s exercise of remedies with respect to all or a material portion of the Collateral or (iii) the commencement of an insolvency proceeding with respect to the Issuer or any Guarantor, then, in any such case, any one or more of Second Lien Creditors (acting in their individual capacity or through one or more affiliates) will have the right, but not the obligation, upon five Business Days advance written notice from such Second Lien Creditors (a “Purchase Notice”) to the First Lien Agent, for the benefit of First Lien Creditors, to acquire from First Lien Creditors all (but not less than all) of the right, title, and interest of First Lien Creditors in and to the First Lien Priority Obligations and the First Lien Loan Documents. The Purchase Notice, if given, will be irrevocable. On the date specified in the Purchase Notice (which will not be more than five Business Days after the receipt by the First Lien Agent of the Purchase Notice), First Lien Creditors will sell to the purchasing Second Lien Creditors and purchasing Second Lien Creditors will purchase from First Lien Creditors, the First Lien Priority Obligations.
On the date of such purchase and sale, purchasing Second Lien Creditors will (i) pay to First Lien Agent, for the benefit of First Lien Creditors, as the purchase price therefor the full amount of all the First Lien Obligations (other than the Excess First Lien Obligations) then outstanding and unpaid, and (ii) agree to reimburse the First Lien Agent and First Lien Creditors for all expenses to the extent earned or due and payable in accordance with the First Lien Documents. Following such purchase, if the Second Lien Creditors receive any early termination or other similar fee payable pursuant to the documents governing First Lien Obligations, and all Second Lien Obligations have been indefeasibly satisfied in full (including all amounts used to purchase the First Lien Obligations) the Second Lien Creditors will turn over such amounts to holders of First Lien Obligations.
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Release of Second Priority Liens
The Intercreditor Agreement provides that if, in connection with (i) any disposition of any Collateral permitted under the terms of the First Lien Documents (other than during the continuance of a Second Lien Actionable Default), (ii) the enforcement or exercise of any rights or remedies with respect to the Collateral, including any disposition of Collateral or (iii) any private or public disposition of all or any portion of the Collateral by the Issuer or one or more Guarantors with the consent of the First Lien Agent after the occurrence and during the continuance of an event of default under the First Lien Documents, which disposition is conducted by the Issuer or such Guarantors with the consent of the First Lien Agent in connection with good faith efforts by the First Lien Agent to collect the First Lien Obligations through the disposition of Collateral (any such disposition, a “Default Disposition”), the First Lien Agent, for itself and on behalf of the other First Lien Creditors, (x) releases any of the First Priority Liens, or (y) releases any Guarantor from its obligations under its guarantee of the First Lien Obligations (in each case, a “Release”), other than any such Release granted following the Discharge of First Lien Priority Obligations, then the Second Priority Liens on such Collateral, and the obligations of such Guarantor under its Guarantee, will be automatically, unconditionally and simultaneously Released (and if the release includes Equity Interests in the Issuer or any Guarantor, the Collateral Agent further agrees to Release those Persons whose Equity Interests are disposed of from all of their obligations under the Second Lien Documents), and the Collateral Agent and the other Second Lien Creditors will promptly execute and deliver such release documents as the First Lien Agent may reasonably request to effectively confirm such Release and as may be otherwise reasonably required to consummate such Release and any related transactions; provided that, (x) in the case of a disposition of Collateral in accordance with clauses (ii) and (iii) above, the Second Priority Liens may not be so Released if the proceeds of such disposition are not applied to repay the First Lien Obligations and permanently reduce any commitments thereunder by a corresponding amount and (y) in the case of a disposition of Collateral in accordance with clause (iii) above, with respect to Collateral that is subject to Article 9 of the Uniform Commercial Code, the Issuer or the relevant Guarantors consummating such Default Disposition have (A) provided the Collateral Agent with the prior written notice that would have been required if the Default Disposition were a disposition of collateral by a secured creditor under Article 9 of the Uniform Commercial Code, and (B) conducted such Default Disposition in a commercially reasonable manner as if such Default Disposition were a disposition of collateral by a secured creditor in accordance with Article 9 of the Uniform Commercial Code.
Whether before or after the Discharge of First Lien Priority Obligations, the Issuer will be entitled to releases of assets included in the Collateral from the Liens securing the notes under any one or more of the following circumstances:
(1)
to enable the Issuer to consummate asset sales and dispositions permitted or not prohibited under the covenant described below under “—Repurchase at the Option of Holders—Asset Sales”; provided, that such Liens will not be released if such sale or disposition is to a Restricted Subsidiary or is subject to the covenant described below under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets”;
(2)
with respect to the assets of a Guarantor that constitute Collateral, upon the release of such Guarantor from its Guarantee; and
(3)
as described under “—Amendment, Supplement and Waiver” below.
The Liens on all Collateral that secures the notes and the Note Guarantees also will be released:
(1)
if the Issuer exercises its legal defeasance option or covenant defeasance option as described below under “—Legal Defeasance and Covenant Defeasance”; or
(2)
upon satisfaction and discharge of the Indenture as described below under “—Satisfaction and Discharge” or payment in full of the principal of, premium, if any, and accrued and unpaid interest on the notes and all other Obligations that are then due and payable.
Subject to the terms of the Security Documents and subject to rights of the holders of the First Lien Obligations, the Issuer and each Guarantor will have the right to remain in possession and retain exclusive control of the Collateral securing the notes, to freely operate such Collateral and to collect, invest and dispose of any income therefrom.
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Amendments to Security Documents
The Intercreditor Agreement provides, subject to limitations (if any) set forth therein, that, in the event the First Lien Agent or the other First Lien Creditors enter into any amendment, waiver or consent in respect of any of the First Lien Security Documents for the purpose of adding to, or deleting from, or waiving or consenting to any departures from any provisions of, any such document or changing in any manner the rights of the First Lien Agent, the other First Lien Creditors, the Issuer or any other grantor thereunder, then such amendment, waiver or consent will apply automatically to any comparable provision of the Security Documents without the consent of the Second Lien Creditors and without any action by any of the foregoing, provided, that no such amendment will (A) remove or release any Collateral subject to a Second Priority Lien, except to the extent that (x) the release is permitted or required under the provisions set forth under the heading “—Insolvency and Liquidation Proceedings” and (y) there is a corresponding release of Collateral from the First Priority Lien, (B) materially and adversely affect the rights of the Second Lien Creditors without the consent of the Second Lien Agent, unless it also affects the First Lien Creditors in a like or similar manner, or (C) impose duties on the Second Lien Agent, without its consent. Notice of such amendment, waiver or consent will be given to the Second Lien Agent no later than 30 days after its effectiveness, provided that the failure to give such notice will not affect the effectiveness and validity thereof.
Certain Bankruptcy and Other Limitations
The ability of the First Lien Agent and the holders of the notes to realize upon the Collateral may be subject to certain bankruptcy law limitations in the event of a bankruptcy of the Issuer or a Guarantor. See “Risk Factors—Risks Related to the Notes—Rights of holders of notes in the collateral may be adversely affected by bankruptcy proceedings.” The ability of the First Lien Agent and the holders of the notes to foreclose on the Collateral may be subject to lack of perfection, the consent of third parties, prior Liens and practical problems associated with the realization of the First Lien Agent’s Lien on the Collateral.
Additionally, the First Lien Agent may need to evaluate the impact of the potential liabilities before determining to foreclose on Collateral consisting of real property (if any) because a secured creditor that holds a Lien on real property may be held liable under environmental laws for the costs of remediating or preventing release or threatened releases of hazardous substances at such real property. Consequently, the First Lien Agent may decline to foreclose on such Collateral or exercise remedies available if it does not receive indemnification to its satisfaction from the holders of the notes.
Compliance with Trust Indenture Act
The Indenture provides that the Issuer will comply with the provisions of TIA §314 to the extent applicable. To the extent applicable, the Issuer will cause TIA §313(b), relating to reports, and TIA §314(d), relating to the release of property or securities subject to the Lien of the Security Documents, to be complied with. Any certificate or opinion required by TIA §314(d) may be made by an officer or legal counsel, as applicable, of the Issuer except in cases where TIA §314(d) requires that such certificate or opinion be made by an independent Person, which Person will be an independent engineer, appraiser or other expert selected by or reasonably satisfactory to the Trustee. Notwithstanding anything to the contrary in this paragraph, the Issuer will not be required to comply with all or any portion of TIA §314(d) if it reasonably determines that under the terms of TIA §314(d) or any interpretation or guidance as to the meaning thereof of the SEC and its staff, including “no action” letters or exemptive orders, all or any portion of TIA §314(d) is inapplicable to any release or series of releases of Collateral.
Without limiting the generality of the foregoing, certain no action letters issued by the SEC have permitted an indenture qualified under the Trust Indenture Act to contain provisions permitting the release of collateral from Liens under such indenture in the ordinary course of the issuer’s business without requiring the issuer to provide certificates and other documents under Section 314(d) of the Trust Indenture Act. The Issuer and the Guarantors may, subject to the provisions of the Indenture, among other things, without any release or consent by the holders of the notes, conduct ordinary course activities with respect to the Collateral, including, without limitation:
| • |
| selling or otherwise disposing of, in any transaction or series of related transactions, any property subject to the Lien of the Security Documents that has become worn out, defective, obsolete or not used or useful in the business; |
| • |
| abandoning, terminating, canceling, releasing or making alterations in or substitutions of any leases or contracts subject to the Lien of the Indenture or any of the Security Documents; |
| • |
| surrendering or modifying any franchise, license or permit subject to the Lien of the Security Documents that it may own or under which it may be operating; |
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| • |
| altering, repairing, replacing, changing the location or position of and adding to its structures, machinery, systems, equipment, fixtures and appurtenances; |
| • |
| granting a license of any intellectual property; |
| • |
| selling, transferring or otherwise disposing of inventory in the ordinary course of business; and |
| • |
| abandoning any intellectual property that is no longer used or useful in the Issuer’s business. |
Optional Redemption
At any time, the Issuer may on any one or more occasions redeem the notes, in whole or in part, upon not less than 30 nor more than 60 days’ notice, at a redemption price of 100% of the principal amount of the notes redeemed, plus accrued and unpaid interest, if any, to the redemption date.
Notice of redemption may, at the Issuer’s option and discretion, be subject to one or more conditions precedent. If any such redemption or notice is subject to satisfaction of one or more conditions precedent, such notice shall state that, in the Issuer’s discretion, the redemption date may be delayed until such time as any or all such conditions shall be satisfied, or such redemption may not occur and such notice may be rescinded in the event that any or all such conditions shall not have been satisfied by the redemption date, or by the redemption date so delayed.
Unless the Issuer defaults in the payment of the redemption price, interest will cease to accrue on the notes or portions thereof called for redemption on the applicable redemption date.
The Trustee shall select the notes to be purchased in the manner described under the caption “—Selection and Notice.”
Mandatory Redemption
Except to the extent that the Issuer may be required to offer to purchase the notes as set forth below under “—Repurchase at the Option of Holders,” the Issuer is not required to make mandatory redemption or sinking fund payments with respect to the notes.
Repurchase at the Option of Holders
Change of Control
If a Change of Control occurs, each holder of notes will have the right to require the Issuer to offer to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that holder’s notes pursuant to the offer described below (a “Change of Control Offer”) at a price in cash on the terms set forth in the Indenture. In the Change of Control Offer, the Issuer will offer a payment (a “Change of Control Payment”) in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest and Additional Interest, if any, on the notes repurchased to, but not including, the date of purchase, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date. Within ten days following any Change of Control, the Issuer will mail such Change of Control Offer by first-class mail, with a copy to the Trustee, to each holder of notes to the address of such holder appearing in the security register (or otherwise in accordance with the procedures of DTC), with the following information:
(1)
a Change of Control Offer is being made pursuant to the covenant entitled “Change of Control,” and that all notes properly tendered pursuant to such Change of Control Offer will be accepted for payment;
(2)
the purchase price and the purchase date, which will be no earlier than 30 days nor later than 60 days from the date such notice is mailed (the “Change of Control Payment Date”);
(3)
any note not properly tendered will remain outstanding and continue to accrue interest;
(4)
unless the Issuer defaults in the payment of the Change of Control Payment, all notes accepted for payment pursuant to the Change of Control Offer will cease to accrue interest on, but not including, the Change of Control Payment Date;
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(5)
holders electing to have any notes purchased pursuant to a Change of Control Offer will be required to surrender the notes, with the form entitled “Option of Holder to Elect Purchase” on the reverse of the notes completed, to the paying agent specified in the notice at the address specified in the notice prior to the close of business on the third business day preceding the Change of Control Payment Date;
(6)
holders will be entitled to withdraw their tendered notes and their election to require the Issuer to purchase such notes; provided that the paying agent receives, not later than the close of business on the last day of the offer period, an electronic mail, facsimile transmission or letter setting forth the name of the holder of the notes, the principal amount of notes tendered for purchase, and a statement that such holder is withdrawing his tendered notes and his election to have such notes purchased;
(7)
if such notice is mailed prior to the occurrence of a Change of Control, stating the Change of Control Offer is conditional on the occurrence of such Change of Control; and
(8)
that holders whose notes are being purchased only in part will be issued new notes equal in principal amount to the unpurchased portion of the notes surrendered, which unpurchased portion must be equal to $2,000 or an integral multiple of $1,000 in excess thereof.
While the notes are in global form and the Issuer makes an offer to purchase all or any portion of the notes pursuant to the Change of Control Offer, a holder may exercise its option to elect for the purchase of the notes through the facilities of DTC, subject to its rules and regulations.
The Issuer will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control pursuant to a Change of Control Offer. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the Indenture, the Issuer will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the Indenture by virtue of such compliance.
On the Change of Control Payment Date, the Issuer will, to the extent lawful:
(1)
accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;
(2)
deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and
(3)
deliver or cause to be delivered to the Trustee for cancellation the notes properly accepted, together with an Officers’ Certificate stating the aggregate principal amount of notes or portions of notes being purchased by the Issuer.
The paying agent will promptly transmit to each holder of notes properly tendered and so accepted the Change of Control Payment for such notes, and the Trustee will promptly authenticate and mail (or cause to be transferred by book-entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered by each such holder, if any; provided that each such new note will be in a principal amount of $2,000 or an integral multiple of $1,000 in excess thereof. Any note so accepted for payment will cease to accrue interest on and after the Change of Control Payment Date. The Issuer will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.
The provisions described above that require the Issuer to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the holders of the notes to require that the Issuer repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.
The Issuer will not be required to make a Change of Control Offer following a Change of Control if (1) a third-party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Issuer and purchases all notes validly tendered and not withdrawn under such Change of Control Offer or (2) notice of redemption has been given pursuant to the Indenture as described under the caption “—Optional Redemption,” unless and until there is a default in payment of the applicable redemption price. Notwithstanding anything to the contrary herein, a Change of Control Offer may be made in advance of a Change of Control and conditioned upon such Change of Control, if a definitive agreement is in place for the Change of Control at the time of making of the Change of Control Offer.
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Future Credit Facilities or other agreements relating to senior Indebtedness to which the Issuer becomes a party may, contain prohibitions of certain events, including events that would constitute a Change of Control. The exercise by the holders of notes of their rights to require the Issuer to repurchase the notes upon a Change of Control could cause a default thereunder, even if the Change of Control itself does not, due to the financial effect of such repurchases on the Issuer. In the event a Change of Control occurs at a time when the Issuer is prohibited from purchasing the notes, the Issuer could seek the consent of its lenders to permit the purchase of the notes or could attempt to refinance the borrowings that contain such prohibition. If the Issuer does not obtain such consent or repay such borrowing, the Issuer will remain prohibited from purchasing the notes and such default could result in amounts outstanding under the Credit Facilities being declared due and payable. In that case, the Issuer’s failure to purchase tendered notes would constitute an Event of Default under the Indenture which could, in turn, constitute a default under the other Indebtedness. Finally, the Issuer’s ability to pay cash to the holders of notes upon a repurchase may be limited by the Issuer’s then existing financial resources. See “Risk Factors—Risks Related to the Notes—Our ability to repurchase the notes with cash upon a change of control or upon an offer to repurchase the notes in the case of an asset sale, as required by the indenture, may be limited.”
The Change of Control purchase feature of the notes may in certain circumstances make more difficult or discourage a sale or takeover of us and, thus, the removal of incumbent management. The Change of Control purchase feature is a result of negotiations between the purchasers of the notes and us. After the Issue Date, we have no present intention to engage in a transaction involving a Change of Control, although it is possible that we could decide to do so in the future. Subject to the limitations discussed below, we could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of Indebtedness outstanding at such time or otherwise affect our capital structure or credit ratings. Restrictions on our ability to incur additional Indebtedness are contained in the covenants described under the captions “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” and “—Certain Covenants—Liens.” Such restrictions in the Indenture can be waived only with the consent of the holders of a majority, or in some instances up to 75%, in principal amount of the notes then outstanding. Except for the limitations contained in such covenants, however, the Indenture contains covenants or provisions that may afford holders of the notes protection in a highly levered transaction.
The definition of “Change of Control” includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of the Issuer and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require the Issuer to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Issuer and its Subsidiaries taken as a whole to another Person or group may be uncertain. In a recent decision, the Chancery Court of the State of Delaware raised the possibility that a change of control occurring as a result of a failure to have “continuing directors” comprising a majority of a board of directors may be unenforceable on public policy grounds.
The existence of a holder’s right to require the Issuer to repurchase such holder’s notes upon the occurrence of a Change of Control may deter a third party from seeking to acquire the Issuer in a transaction that would constitute a Change of Control.
The provisions under the Indenture relative to our obligation to make an offer to repurchase the notes as a result of a Change of Control may be waived or modified with the written consent of the holders of a majority in principal amount of the notes.
Asset Sales
The Issuer will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:
(1)
the Issuer (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the Fair Market Value (measured as of the date of the definitive agreement with respect to such Asset Sale) of the assets or Equity Interests issued or sold or otherwise disposed of; and
(2)
at least 75% of the consideration received in the Asset Sale by the Issuer or such Restricted Subsidiary is in the form of cash or Cash Equivalents; provided, however, to the extent that any disposition in such Asset Sale was of Collateral, the non-cash consideration received is pledged as Collateral in accordance with the Security Documents substantially simultaneously with such sale, in accordance with the requirements set forth in the Indenture. For purposes of this provision, each of the following will be deemed to be cash:
(a)
any liabilities, as shown on the Issuer’s most recent consolidated balance sheet, of the Issuer or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Note Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases the Issuer or such Restricted Subsidiary from further liability;
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(b)
any securities, notes or other obligations received by the Issuer or any such Restricted Subsidiary from such transferee that are contemporaneously, subject to ordinary settlement periods, converted by the Issuer or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion; and
(c)
any stock or assets of the kind referred to in clauses (2) or (4) of the next paragraph of this covenant.
Within 360 days after the receipt of any Net Proceeds from an Asset Sale, the Issuer (or the applicable Restricted Subsidiary, as the case may be) may apply such Net Proceeds:
(1)
to repay Indebtedness and other Obligations under a Credit Facility and to the extent such Credit Facility is a revolving facility, to correspondingly reduce commitments with respect thereto;
(2)
to acquire all or substantially all of the assets of, or any Capital Stock of, another Oil and Gas Business, if, after giving effect to any such acquisition of Capital Stock, the Oil and Gas Business is or becomes, or all or substantially all of the assets thereof are acquired by, a Restricted Subsidiary of the Issuer;
(3)
to make a capital expenditure; or
(4)
to acquire other assets that are not classified as current assets under GAAP and that are used or useful in an Oil and Gas Business; provided that the assets (including Voting Stock) acquired with the Net Proceeds from any disposition of Collateral are pledged as Collateral in accordance with the Security Documents concurrently with such acquisition in accordance with the requirements of the Indenture.
Pending the final application of any Net Proceeds, the Issuer may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the Indenture.
Any Net Proceeds from Asset Sales that are not applied or invested as provided in the second paragraph of this covenant will constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $5.0 million, the Issuer will, within 30 days thereof, make one or more offers to the holders of the notes (and, at the option of the Issuer, the holders of Other Pari Passu Obligations) to purchase notes (and Other Pari Passu Obligations) pursuant to and subject to the conditions contained in the Indenture (each, an “Asset Sale Offer”), that are $2,000 or an integral multiple of $1,000 in excess thereof that may be purchased out of the Excess Proceeds at an offer price in cash in an amount equal to 100% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the date fixed for the closing of such offer, in accordance with the procedures set forth in the Indenture. The Issuer will commence an Asset Sale Offer with respect to Excess Proceeds within 30 days after the date that Excess Proceeds exceeds $5.0 million by mailing (or transmitting otherwise in accordance with the procedures of DTC), the notice required pursuant to the terms of the Indenture, with a copy to the Trustee. To the extent that the aggregate amount of notes and such Other Pari Passu Obligations tendered pursuant to an Asset Sale Offer is less than the Excess Proceeds, the Issuer may use any remaining Excess Proceeds for any purpose not otherwise prohibited by the Indenture. If the aggregate principal amount of notes or the Other Pari Passu Obligations surrendered by such holders thereof exceeds the amount of Excess Proceeds, the notes and such Other Pari Passu Obligations will be purchased on a pro rata basis based on the accreted value or principal amount of the notes or such Other Pari Passu Obligations tendered. Upon completion of any such Asset Sale Offer, the amount of Excess Proceeds shall be reset at zero.
The Issuer will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the Indenture, the Issuer will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the Indenture by virtue of such compliance.
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The agreements governing the Issuer’s other Indebtedness contain, and future agreements may contain, prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale and including repurchases of or other prepayments in respect of the notes. The exercise by the holders of notes of their right to require the Issuer to repurchase the notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchases on the Issuer. In the event a Change of Control or Asset Sale occurs at a time when the Issuer is prohibited from purchasing notes, the Issuer could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If the Issuer does not obtain a consent or repay those borrowings, the Issuer will remain prohibited from purchasing notes. In that case, the Issuer’s failure to purchase tendered notes would constitute an Event of Default under the Indenture, which could, in turn, constitute a default under the other indebtedness. Finally, the Issuer’s ability to pay cash to the holders of notes upon a repurchase may be limited by the Issuer’s then existing financial resources. See “Risk Factors—Risks Related to the Notes—Our ability to repurchase the notes with cash upon a change of control or upon an offer to repurchase the notes in the case of an asset sale, as required by the indenture, may be limited.”
Selection and Notice
If less than all of the notes are to be redeemed at any time, the Trustee will select notes for redemption on a pro rata basis or by lot or such similar method (and in the case of global notes, in accordance with the procedures of DTC), unless otherwise required by law or applicable stock exchange requirements; provided that no notes of $2,000 or less shall be purchased or redeemed in part.
Notices of redemption will be mailed by first-class mail (or transmitted otherwise in accordance with the procedures of DTC) at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the Indenture. Notices of redemption may not be conditional.
If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unpurchased or unredeemed portion of the original note purchased or redeemed in part will be issued in the name of the holder of notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of notes called for redemption.
Certain Covenants
Restricted Payments
The Issuer will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:
(1)
declare or pay any dividend or make any other payment or distribution on account of the Issuer’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving the Issuer or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Issuer’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Issuer and other than dividends or distributions payable to the Issuer or a Restricted Subsidiary of the Issuer);
(2)
purchase, redeem, defease or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Issuer) any Equity Interests of the Issuer or any direct or indirect parent of the Issuer;
(3)
make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Indebtedness of the Issuer or any Guarantor that is contractually subordinated to the notes or to any Note Guarantee (excluding any intercompany Indebtedness between or among the Issuer and any of its Restricted Subsidiaries), except (a) a payment of interest or principal at the Stated Maturity thereof or (b) any Plan of Reorganization Indebtedness at the Stated Maturity thereof or at any other time; or
(4)
make any Restricted Investment;
(all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as “Restricted Payments”),
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unless, at the time of and after giving effect to such Restricted Payment:
(1)
no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;
(2)
the Issuer would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock;” and
(3)
such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Issuer and its Restricted Subsidiaries since the Issue Date (excluding Restricted Payments permitted by clauses (2), (3), (4), (6) and (8) of the next succeeding paragraph), is less than the sum, without duplication, of:
(a)
50% of the Consolidated Net Income of the Issuer for the period (taken as one accounting period) from the beginning of the first fiscal quarter commencing after the Issue Date to the end of the Issuer’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit); plus
(b)
100% of the aggregate net cash proceeds received by the Issuer since the Issue Date as a contribution to its common equity capital or from the issue or sale of Equity Interests of the Issuer (other than Disqualified Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of the Issuer that have been converted into or exchanged for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of the Issuer); provided that any equity offering consummated on or within 15 days of the Issue Date shall be excluded from the Restricted Payments permitted pursuant to this clause (b); plus
(c)
to the extent that any Restricted Investment that was made after the Issue Date is sold for cash or otherwise liquidated or repaid for cash, the lesser of (i) the cash return of capital with respect to such Restricted Investment (less the cost of disposition, if any) and (ii) the initial amount of such Restricted Investment; plus
(d)
to the extent that any Unrestricted Subsidiary of the Issuer designated as such after the Issue Date is redesignated as a Restricted Subsidiary after the Issue Date, the lesser of (i) the Fair Market Value of the Issuer’s Investment in such Subsidiary as of the date of such redesignation or (ii) such Fair Market Value as of the date on which such Subsidiary was originally designated as an Unrestricted Subsidiary after the Issue Date; plus
(e)
50% of any dividends received by the Issuer or a Restricted Subsidiary of the Issuer that is a Guarantor after the Issue Date from an Unrestricted Subsidiary of the Issuer, to the extent that such dividends were not otherwise included in the Consolidated Net Income of the Issuer for such period.
So long as no Default has occurred and is continuing or would be caused thereby, the preceding provisions will not prohibit:
(1)
the payment of any dividend or the consummation of any irrevocable redemption within 60 days after the date of declaration of the dividend or giving of the redemption notice, as the case may be, if at the date of declaration or notice, the dividend or redemption payment would have complied with the provisions of the Indenture;
(2)
the making of any Restricted Payment in exchange for, or out of the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of the Issuer) of, Equity Interests of the Issuer (other than Disqualified Stock) or from the substantially concurrent contribution of common equity capital to the Issuer; provided that the amount of any such net cash proceeds that are utilized for any such Restricted Payment will be excluded from clause (3)(b) of the preceding paragraph;
(3)
the repurchase, redemption, defeasance or other acquisition or retirement for value of Indebtedness of the Issuer or any Guarantor that is contractually subordinated to the notes or to any Note Guarantee with the net cash proceeds from a substantially concurrent incurrence of Permitted Refinancing Indebtedness;
(4)
the payment of any dividend (or, in the case of any partnership or limited liability company, any similar distribution) by a Restricted Subsidiary of the Issuer to the holders of its Equity Interests on a pro rata basis;
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(5)
the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Issuer or any Restricted Subsidiary of the Issuer held by any current or former officer, director or employee of the Issuer or any of its Restricted Subsidiaries pursuant to any equity subscription agreement, stock option agreement, shareholders’ agreement or similar agreement; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $500,000 in any twelve-month period;
(6)
the repurchase of Equity Interests deemed to occur upon the exercise of stock options to the extent such Equity Interests represent a portion of the exercise price of those stock options;
(7)
the declaration and payment of regularly scheduled or accrued dividends to holders of any class or series of Disqualified Stock of the Issuer or any Restricted Subsidiary of the Issuer issued on or after the Issue Date in accordance with the Fixed Charge Coverage Ratio test described below under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock;” or
(8)
other Restricted Payments in an aggregate amount not to exceed $5.0 million since the Issue Date.
The amount of all Restricted Payments (other than cash) will be the Fair Market Value on the date of the Restricted Payment of the assets or securities proposed to be transferred or issued by the Issuer or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The Fair Market Value of any assets or securities that are required to be valued by this covenant will be determined by the Board of Directors of the Issuer whose resolution with respect thereto will be delivered to the Trustee. The Board of Directors’ determination must be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if the Fair Market Value exceeds $5.0 million. For purposes of determining compliance with this covenant, if a Restricted Payment meets the criteria of more than one of the exceptions described in clauses (1) through (9) above, or is entitled to be made according to the first paragraph of this covenant, the Issuer may, in its sole discretion, classify the Restricted Payment in any manner that complies with this covenant.
Incurrence of Indebtedness and Issuance of Preferred Stock
The Issuer will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), and the Issuer will not issue any Disqualified Stock or any shares of preferred stock and will not permit any of its Restricted Subsidiaries to issue any Disqualified Stock or any shares of preferred stock; provided, however, that the Issuer and the Guarantors may incur Indebtedness (including Acquired Debt), issue Disqualified Stock or issue preferred stock, if the Fixed Charge Coverage Ratio for the Issuer and the Guarantors on a consolidated basis for the most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or such preferred stock is issued, as the case may be, would have been at least 2.5 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock or the preferred stock had been issued, as the case may be, at the beginning of such four-quarter period.
The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Debt”):
(1)
the incurrence by the Issuer and any Guarantor of (I) additional Indebtedness under Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) not to exceed the greater of (a) $35.0 million and (b) 15% of Adjusted Consolidated Net Tangible Assets, in each case, less the aggregate amount of all Net Proceeds of Asset Sales applied by the Issuer or any of its Restricted Subsidiaries since the Issue Date to repay any term Indebtedness under a Credit Facility or to repay any revolving credit Indebtedness under a Credit Facility and effect a corresponding commitment reduction thereunder pursuant to the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales;” and (II) letters of credit under Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) not to exceed $10.0 million; provided that notwithstanding the foregoing, in no event shall Indebtedness pursuant to Additional Notes under this clause that is incurred after the Issue Date exceed $10.0 million without the prior written consent of holders of at least 75% in aggregate principal amount of the notes then outstanding;
(2)
the incurrence by the Issuer and its Restricted Subsidiaries of Existing Indebtedness (other than the Indebtedness described in clauses (1) and (3) of this paragraph); provided that after giving effect to the exchange of $27.3 million principal amount of Second Lien Notes, the amount of Second Lien Notes is $125.2 million;
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(3)
the incurrence by the Issuer and the Guarantors of Indebtedness represented by the notes and the related Note Guarantees issued on the Issue Date and the exchange notes and the related Note Guarantees to be issued pursuant to the registration rights agreement;
(4)
the incurrence by the Issuer or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of design, construction, installation or improvement of property, plant or equipment used in the business of the Issuer or any of its Restricted Subsidiaries, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (4), not to exceed $5.0 million at any time outstanding;
(5)
the incurrence by the Issuer or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge any Indebtedness (other than intercompany Indebtedness) that was permitted by the Indenture to be incurred under the first paragraph of this covenant or clauses (2), (3), (5) or (15) of this paragraph;
(6)
the incurrence by the Issuer or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Issuer and any of its Restricted Subsidiaries; provided, however, that:
(a)
if the Issuer or any Guarantor is the holder of such Indebtedness and the borrower is not the Issuer or a Guarantor, such Indebtedness (i) must be evidenced by a promissory note which note shall be pledged to the Collateral Agent in favor of the holders of notes, subject to the Intercreditor Agreement, (ii) must be expressly subordinated to the prior payment in full in cash of all Obligations then due with respect to the notes, in the case of the Issuer, or the Note Guarantee, in the case of a Guarantor and (iii) shall not exceed $5.0 million at any one time outstanding; and
(b)
(i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Issuer or a Restricted Subsidiary of the Issuer and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either the Issuer or a Restricted Subsidiary of the Issuer will be deemed, in each case, to constitute an incurrence of such Indebtedness by the Issuer or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);
(7)
the issuance by any of the Issuer’s Restricted Subsidiaries to the Issuer or to any of its Restricted Subsidiaries of shares of preferred stock; provided, however, that:
(a)
any subsequent issuance or transfer of Equity Interests that results in any such preferred stock being held by a Person other than the Issuer or a Restricted Subsidiary of the Issuer; and
(b)
any sale or other transfer of any such preferred stock to a Person that is not either the Issuer or a Restricted Subsidiary of the Issuer,
will be deemed, in each case, to constitute an issuance of such preferred stock by such Restricted Subsidiary that was not permitted by this clause (7);
(8)
the incurrence by the Issuer or any of its Restricted Subsidiaries of Hedging Obligations in the ordinary course of business and not for speculative purposes;
(9)
the guarantee by the Issuer or any of the Guarantors of Indebtedness of the Issuer or a Restricted Subsidiary of the Issuer that was permitted to be incurred by another provision of this covenant; provided that if the Indebtedness being guaranteed is subordinated to or pari passu with the notes, then the Guarantee shall be subordinated or pari passu, as applicable, to the same extent as the Indebtedness guaranteed;
(10)
the incurrence by the Issuer or any of its Restricted Subsidiaries of Indebtedness in respect of workers’ compensation claims, self-insurance obligations, bankers’ acceptances, performance and surety bonds in the ordinary course of business;
(11)
the incurrence by the Issuer or any of its Restricted Subsidiaries of Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument inadvertently drawn against insufficient funds, so long as such Indebtedness is covered within five business days;
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(12)
the incurrence by the Issuer or any of its Restricted Subsidiaries of Indebtedness in respect of bid, performance, surety and similar bonds issued for the account of the Issuer and any of its Restricted Subsidiaries in the ordinary course of business, including guarantees and obligations of the Issuer and any of its Restricted Subsidiaries with respect to letters of credit supporting such obligations (in each other than an obligation for money borrowed);
(13)
the incurrence by the Issuer or any of its Restricted Subsidiaries of obligations relating to net gas balancing positions arising in the ordinary course of business and consistent with past practice;
(14)
the incurrence by the Issuer or any of its Restricted Subsidiaries of Indebtedness arising from agreements of the Issuer or any of its Restricted Subsidiaries providing for indemnification, adjustment of purchase price or similar obligations, in each case, incurred or assumed in connection with the disposition of any business, assets or Capital Stock of a Subsidiary, provided that the maximum aggregate liability in respect of all such Indebtedness shall at no time exceed the gross proceeds actually received by the Issuer and its Restricted Subsidiaries in connection with such disposition; and
(15)
the incurrence by the Issuer or any of the Guarantors of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (15), not to exceed $5.0 million.
The Indenture provides that the Issuer will not incur, and will not permit any Guarantor to incur, any Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of the Issuer or such Guarantor unless such Indebtedness is also contractually subordinated in right of payment to the notes and the applicable Note Guarantee on substantially identical terms; provided, however, that no Indebtedness will be deemed to be contractually subordinated in right of payment to any other Indebtedness of the Issuer solely by virtue of being unsecured or by virtue of being secured on a first or junior Lien basis.
For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of proposed Indebtedness meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (15) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Issuer will be permitted to divide and classify such item of Indebtedness on the date of its incurrence, or later reclassify all or a portion of such item of Indebtedness, in any manner that complies with this covenant. The accrual of interest payable in cash in accordance with the terms of such Indebtedness in the ordinary course of business, the reclassification of preferred stock as Indebtedness due to a change in accounting principles, and the payment of dividends on Disqualified Stock in the form of additional shares of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant; provided, in each such case, that the amount of any such accrual or payment is included in Fixed Charges of the Issuer as accrued. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Issuer or any Restricted Subsidiary may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in exchange rates or currency values.
The amount of any Indebtedness outstanding as of any date will be:
(1)
the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;
(2)
the principal amount of the Indebtedness, in the case of any other Indebtedness; and
(3)
in respect of Indebtedness of another Person secured by a Lien on the assets of the specified Person, the lesser of:
(a)
the Fair Market Value of such assets at the date of determination; and
(b)
the amount of the Indebtedness of the other Person.
Liens
The Issuer will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, assume or suffer to exist any Lien of any kind on any asset now owned or hereafter acquired, except Permitted Liens unless contemporaneously with the incurrence of such Liens, it has made or will make effective provisions whereby the notes or any Note Guarantee will be secured by such Lien equally and ratably with (or, if such other Indebtedness is contractually subordinated to the notes, prior to) all other Indebtedness secured by such Lien for so long as such other Indebtedness is secured by such Lien.
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Dividend and Other Payment Restrictions Affecting Subsidiaries
The Issuer will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:
(1)
pay dividends or make any other distributions on its Capital Stock to the Issuer or any of its Restricted Subsidiaries, or with respect to any other interest or participation in, or measured by, its profits, or pay any Indebtedness owed to the Issuer or any of its Restricted Subsidiaries;
(2)
make loans or advances to the Issuer or any of its Restricted Subsidiaries; or
(3)
sell, lease or transfer any of its properties or assets to the Issuer or any of its Restricted Subsidiaries.
However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:
(1)
agreements governing Existing Indebtedness as in effect on the Issue Date and Credit Facilities permitted to be entered into under the Indenture and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements; provided that the amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the Issue Date;
(2)
the Indenture, the notes, the Note Guarantees and the Security Documents;
(3)
applicable law, rule, regulation or order;
(4)
any instrument governing Indebtedness or Capital Stock of a Person acquired by the Issuer or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired; provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the Indenture to be incurred;
(5)
customary non-assignment provisions in contracts and licenses entered into in the ordinary course of business;
(6)
purchase money obligations for property acquired in the ordinary course of business and Capital Lease Obligations that impose restrictions on the property purchased or leased of the nature described in clause (3) of the first paragraph of this covenant;
(7)
any agreement for the sale or other disposition of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending the sale or other disposition;
(8)
Permitted Refinancing Indebtedness; provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being extended, renewed, refunded, refinanced, defeased or discharged (as determined in good faith by the Board of Directors of the Issuer);
(9)
Liens permitted to be incurred under the provisions of the covenant described above under the caption “—Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;
(10)
provisions limiting the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements and other similar agreements entered into with the approval of the Issuer’s Board of Directors, which limitation is applicable only to the assets that are the subject of such agreements;
(11)
restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;
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(12)
in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:
(a)
that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in oil and gas properties), license or similar contract, or the assignment or transfer of any such lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in oil and gas properties), license (including, without limitation, licenses of intellectual property) or other contract;
(b)
contained in mortgages, pledges or other security agreements permitted under the indenture securing Indebtedness of the Issuer or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements;
(c)
contained in any agreement creating Hedging Obligations permitted from time to time under the Indenture; or
(d)
pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of the Issuer or any Restricted Subsidiary; and
(13)
any customary encumbrances or restrictions imposed pursuant to any agreement of the type described in the definition of “Permitted Business Investment”; provided that the Issuer shall, and shall cause each Restricted Subsidiary to, make all commercially reasonable efforts to prevent any asset or property, including but not limited to Permitted Business Investments, from being subject to any encumbrances or restrictions.
Merger, Consolidation or Sale of Assets
The Issuer will not, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not the Issuer is the surviving corporation); or (2) sell, assign, transfer, convey or otherwise dispose of all or substantially all of the properties or assets of the Issuer and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person, unless:
(1)
either: (a) the Issuer is the surviving corporation; or (b) the Person formed by or surviving any such consolidation or merger (if other than the Issuer) or to which such sale, assignment, transfer, conveyance or other disposition has been made is a corporation organized or existing under the laws of the United States, any state of the United States or the District of Columbia;
(2)
the Person formed by or surviving any such consolidation or merger (if other than the Issuer) or the Person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all the obligations of the Issuer under the notes, the Indenture, the registration rights agreement and the Security Documents pursuant to agreements reasonably satisfactory to the Trustee;
(3)
immediately after such transaction, no Default or Event of Default exists;
(4)
the Issuer or the Person formed by or surviving any such consolidation or merger (if other than the Issuer), or to which such sale, assignment, transfer, conveyance or other disposition has been made would, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock;” and
(5)
the Trustee has received an Opinion of Counsel and Officers’ Certificate to the effect that such transaction complies with the foregoing.
In addition, the Issuer will not, directly or indirectly, lease all or substantially all of the properties and assets of it and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to any other Person.
This “Merger, Consolidation or Sale of Assets” covenant will not apply to:
(1)
a merger of the Issuer with an Affiliate solely for the purpose of reincorporating the Issuer in another jurisdiction; or
(2)
any consolidation or merger, or any sale, assignment, transfer, conveyance, lease or other disposition of assets between or among the Issuer and its Restricted Subsidiaries.
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Transactions with Affiliates
The Issuer will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of the Issuer (each, an “Affiliate Transaction”), unless:
(1)
the Affiliate Transaction is on terms that are no less favorable to the Issuer or the relevant Restricted Subsidiary (as determined in good faith by the Board of Directors of the Issuer) than those that would have been obtained in a comparable transaction by the Issuer or such Restricted Subsidiary with an unrelated Person; and
(2)
the Issuer delivers to the Trustee:
(a)
with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $1.0 million, a resolution of the Board of Directors of the Issuer set forth in an Officers’ Certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors of the Issuer; and
(b)
with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $5.0 million, an opinion as to the fairness to the Issuer or such Subsidiary of such Affiliate Transaction from a financial point of view issued by an accounting, appraisal or investment banking firm of national standing.
The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:
(1)
any employment agreement, employee benefit plan, officer or director indemnification agreement or any similar arrangement entered into by the Issuer or any of its Restricted Subsidiaries in the ordinary course of business and payments pursuant thereto;
(2)
transactions between or among the Issuer and/or its Restricted Subsidiaries;
(3)
transactions with a Person (other than an Unrestricted Subsidiary of the Issuer) that is an Affiliate of the Issuer solely because the Issuer owns, directly or through a Restricted Subsidiary, an Equity Interest in, or controls, such Person;
(4)
payment of reasonable directors’ fees to Persons who are not otherwise Affiliates of the Issuer;
(5)
any issuance of Equity Interests (other than Disqualified Stock) of the Issuer to Affiliates of the Issuer; and
(6)
transactions effected pursuant to agreements in effect on the Issue Date and described in the offering circular relating to the initial issuance of the notes and any amendment, modification or replacement of such agreement (so long as such amendment or replacement is not less favorable to the Issuer, any Restricted Subsidiary or the holders, taken as a whole, than the original agreement as in effect on the Issue Date as determined in good faith by the Board of Directors of the Issuer).
Business Activities
The Issuer will not, and will not permit any of its Restricted Subsidiaries to, engage in any business other than an Oil and Gas Business, except to such extent as would not be material to the Issuer and its Restricted Subsidiaries taken as a whole.
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Additional Note Guarantees
If the Issuer or any of its Restricted Subsidiaries acquires or creates another Domestic Subsidiary after the Issue Date, then the Issuer will (1) cause that newly acquired or created Domestic Subsidiary to execute a supplemental indenture pursuant to which it will become a Guarantor, (2) cause the newly acquired or created Domestic Subsidiary to execute and deliver to the Trustee and the Collateral Agent amendments to the Security Documents, additional Security Documents and Intercreditor Agreement, and take such other action as may be necessary or advisable in the determination of the Collateral Agent to grant to the Collateral Agent, for the benefit of the holders, a perfected Lien in the assets (other than Excluded Assets) of such Domestic Subsidiary to have such assets included as Collateral, including the filing of Uniform Commercial Code financing statements in such jurisdiction or such other actions as may be required by the Security Documents, (3) cause that newly acquired or created Domestic Subsidiary to take such actions necessary or as the Collateral Agent reasonably determines to be necessary or advisable to grant to the Collateral Agent for the benefit of the holders a perfected Lien in the assets other than Excluded Assets of such new Domestic Subsidiary, including the filing of Uniform Commercial Code financing statements in such jurisdiction as may be required by the Security Documents or by law or as may be reasonably requested by the Collateral Agent, (4) cause that newly acquired or created Domestic Subsidiary to take such further action and execute and deliver such other documents reasonably requested by the Trustee or the Collateral Agent to effectuate the foregoing, and (5) deliver an Officers’ Certificate and an Opinion of Counsel satisfactory to the Trustee and Collateral Agent, in each case, within 30 days of the date on which the Domestic Subsidiary was acquired or created as contemplated by the Indenture, Security Documents and Intercreditor Agreement.
Designation of Restricted and Unrestricted Subsidiaries
The Board of Directors of the Issuer may designate any Restricted Subsidiary (including any newly acquired or newly formed Subsidiary or Person that becomes a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary if that designation would not cause a Default and the Subsidiary meets the definition of “Unrestricted Subsidiary.” If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by the Issuer and its Restricted Subsidiaries in the Subsidiary designated as an Unrestricted Subsidiary will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the covenant described above under the caption “—Restricted Payments” or under one or more clauses of the definition of Permitted Investments, as determined by the Issuer. That designation will only be permitted if the Investment would be permitted at that time (other than pursuant to clause (10) of the definition of Permitted Investments) and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. The Board of Directors of the Issuer may redesignate any Unrestricted Subsidiary to be a Restricted Subsidiary if that redesignation would not cause a Default.
Any designation of a Subsidiary of the Issuer as an Unrestricted Subsidiary will be evidenced to the Trustee by filing with the Trustee a certified copy of a resolution of the Board of Directors giving effect to such designation and an Officers’ Certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of the Issuer as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock,” the Issuer will be in default of such covenant. The Board of Directors of the Issuer may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of the Issuer; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Issuer of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period; and (2) no Default or Event of Default would be in existence following such designation.
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Impairment of Security Interest
Subject to the Intercreditor Agreement, neither the Issuer nor any of the Restricted Subsidiaries will take or omit to take any action which would adversely affect or impair in any material respect the Liens in favor of the Collateral Agent with respect to the Collateral, except as otherwise permitted or required by the Security Documents or the Indenture. Neither the Issuer nor any of the Restricted Subsidiaries will enter into any agreement that requires the proceeds received from any sale of Collateral to be applied to repay, redeem, defease or otherwise acquire or retire any Indebtedness of any Person, other than the notes and Second Lien Obligations, unless such agreement permits such Issuer or Restricted Subsidiary to first repay, or offer to repay, the notes and the Second Lien Obligations. The Issuer shall, and shall cause each Guarantor to, at its sole cost and expense, execute and deliver all such agreements and instruments as the Collateral Agent or the Trustee shall reasonably request to more fully or accurately describe the property intended to be Collateral or the obligations intended to be secured by the Security Documents. The Issuer shall, and shall cause each Guarantor to, at its sole cost and expense, file any such notice filings or other agreements or instruments as may be reasonably necessary or desirable under applicable law to perfect the Liens created by the Security Documents at such times and at such places as the Collateral Agent or the Trustee may reasonably request.
Real Estate Mortgages and Filings
With respect to any real property or any Oil and Gas Properties (individually and collectively, the “Premises”) owned by the Issuer or a Domestic Subsidiary (other than Unrestricted Subsidiaries) on the Issue Date and with respect to any such Premises to be acquired by the Issuer or a Domestic Subsidiary (other than Unrestricted Subsidiaries) after the Issue Date, subject to the terms of the Intercreditor Agreement:
(1)
The Issuer shall deliver to the Collateral Agent, as mortgagee, fully executed counterparts of Mortgages, duly executed by the Issuer or the applicable Domestic Subsidiary, together with evidence of the completion (or satisfactory arrangements for the completion) of all recordings and filings of such Mortgage as may be necessary to create a valid, perfected Lien, subject to Permitted Liens, against the Premises purported to be covered thereby;
(2)
The Issuer shall deliver to the Collateral Agent mortgagee’s title insurance policies or title opinions (as applicable) in favor of the Collateral Agent, as mortgagee for the ratable benefit of the Collateral Agent, the Trustee and the holders in an amount equal to 90% of the Fair Market Value of the Premises purported to be covered by the related Mortgage, insuring that title to such property is marketable or opining to the title of such property, as applicable, and that the interests created by the Mortgage constitute valid Liens thereon free and clear of all Liens, defects and encumbrances other than Permitted Liens together with customary endorsements, coinsurance and reinsurance typical for the applicable jurisdiction and accompanied by evidence of the payment in full of all premiums thereon;
(3)
The Issuer shall deliver to the Collateral Agent, with respect to each of the covered Premises, the most recent survey of such Premises prepared on or on behalf of the Issuer, together with either (i) an updated survey certification in favor of the Trustee and the Collateral Agent from the applicable surveyor stating that, based on a visual inspection of the property and the knowledge of the surveyor, there has been no change in the facts depicted in the survey or (ii) an affidavit from the Issuer and the Guarantors stating that there has been no change sufficient for the title insurance company to remove all standard survey exceptions and issue the customary endorsements;
(4)
The Issuer shall deliver to the Collateral Agent, with respect to each of the covered Premises, all abstracts of title, title reports to other title information conducted on behalf of the Issuer with respect to the Premises and any reserve reports relating to Hydrocarbon Interests attributable to or included in the Collateral; and
(5)
The Issuer shall deliver an opinion(s) of approved counsel of the Issuer confirming that the Mortgages and Security Documents create a Lien, subject only to Permitted Liens, on all Collateral, which shall be from local counsel or special regulatory counsel in each state where a Premises is located covering the enforceability of the relevant Mortgages;
in each case, using commercially reasonable efforts to comply with the foregoing by the Issue Date but, in any event, no later than 60 days thereafter.
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Leasehold Mortgages and Filings; Landlord Waivers
The Issuer and each of its Domestic Subsidiaries (other than any Unrestricted Subsidiary) agreed to use commercially reasonable efforts to deliver Mortgages with respect to the Issuer’s or such Domestic Subsidiary’s leasehold interests in any premises material to the business taken as a whole (the “Leased Premises”) occupied by the Issuer or such Domestic Subsidiary (other than any Unrestricted Subsidiary) pursuant to leases which may be mortgaged by their terms or the terms of the landlord consents (collectively, the “Leases,” and individually, a “Lease”) in each case using commercially reasonable efforts to comply with the foregoing by the Issue Date but, in any event, no later than 60 days thereafter.
With respect to any leasehold Mortgage delivered pursuant to the immediately preceding paragraph, the Issuer or the applicable Subsidiary agreed to provide to the Trustee all of the items described in clauses (2), (3) and (5) of “—Real Estate Mortgages and Filings” above and in addition agreed to use their respective commercially reasonable efforts to obtain an agreement executed by the lessor under the Lease, whereby the lessor consents to the Mortgage and waives or subordinates its landlord Lien (whether granted by the instrument creating the leasehold estate or by applicable law), if any, and which shall be entered into by the Collateral Agent.
The Issuer and each of its Domestic Subsidiaries that is a lessee of, or becomes a lessee of, real property material to the business, is, and will be, required to use commercially reasonable efforts to deliver to the Collateral Agent a landlord waiver, in the form reasonably acceptable to the Collateral Agent executed by the lessor of such real property; provided that in the case where such lease is a lease in existence on the Issue Date, the Issuer or its Domestic Subsidiary that is the lessee thereunder shall have 60 days from the Issue Date to satisfy such requirement.
Advances to Subsidiaries
All advances to Restricted Subsidiaries made by the Issuer after the Issue Date will be evidenced by intercompany notes in favor of the Issuer. These intercompany notes will be pledged pursuant to the Security Documents as Collateral to secure the notes. Each intercompany note will be payable upon demand and will bear interest at the same rate as the notes and will be subordinated in right of payment to all existing Senior Debt of the Restricted Subsidiary to which the loan is made. “Senior Debt” of Restricted Subsidiaries for the purposes of the intercompany notes will be defined as all Indebtedness of the Restricted Subsidiaries that is not specifically by its terms made pari passu with or junior to the intercompany notes. Repayments of principal with respect to any intercompany notes will be required to be pledged pursuant to the Security Documents as Collateral to secure the notes until such amounts are advanced to a Subsidiary in accordance with the Indenture.
The Issuer will not permit any Restricted Subsidiary in respect of which the Issuer is a creditor by virtue of an intercompany note to incur any Indebtedness that is subordinate or junior in right of payment to any Senior Debt of such Restricted Subsidiary and senior in any respect in right of payment to any intercompany note.
Payments for Consent
The Issuer will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, pay or cause to be paid any consideration to or for the benefit of any holder of notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the notes unless such consideration is offered to be paid and is paid to all holders of the notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or agreement.
Post-Closing
Certain security interests in the Collateral may not have been in place on the Issue Date or may not have been perfected on the Issue Date. The Issuer and the Guarantors agreed to use their respective commercially reasonable efforts to perfect on the Issue Date the security interests in the Collateral for the benefit of the holders of the notes that were created on the Issue Date but, to the extent any such security interest or liens were not perfected by such date, the Issuer and the Guarantors agreed to do or cause to be done all acts and things that may be required, including using commercially reasonable efforts to obtain any required consents from third parties, to have all security interests in the Collateral duly created and enforceable and perfected, in each case solely to the extent required by the Security Documents, promptly following the Issue Date, but in any event no later than the date 60 days thereafter. In addition, the Security Documents may not require that all Collateral be perfected if such Collateral cannot be perfected by the filing of UCC financing statements or the recording of mortgages or deeds of trust.
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Further Assurances
The Issuer and the Guarantors agreed to execute any and all further documents, financing statements, agreements and instruments, and take all further action that may be required under applicable law, or that the Collateral Agent may reasonably request, in order to grant, preserve, protect and perfect the validity and priority of the security interests created or intended to be created by the Security Documents in the Collateral. In addition, from time to time, the Issuer will reasonably promptly secure the obligations under the Indenture and the Security Documents by pledging or creating, or causing to be pledged or created, perfected security interests with respect to the Collateral. The Issuer shall deliver or cause to be delivered to the Collateral Agent all such instruments and documents as the Collateral Agent shall reasonably request to evidence compliance with this covenant.
Reports
Whether or not required by the rules and regulations of the SEC, so long as any notes are outstanding, the Issuer and the Guarantors will make available on a publicly available website, within the time periods specified in the SEC’s rules and regulations:
(1)
all quarterly and annual reports that would be required to be filed with the SEC on Forms 10-Q and 10-K if the Issuer were required to file such reports; and
(2)
all current reports that would be required to be filed with the SEC on Form 8-K if the Issuer were required to file such reports.
All such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10-K will include a report on the Issuer’s consolidated financial statements by the Issuer’s certified independent accountants. In addition, the Issuer will file a copy of each of the reports referred to in clauses (1) and (2) above with the SEC for public availability within the time periods specified in the rules and regulations applicable to such reports (unless the SEC will not accept such a filing) and will post the reports on its website within those time periods.
If, at any time after consummation of the exchange offer contemplated by the registration rights agreement, the Issuer is no longer subject to the periodic reporting requirements of the Exchange Act for any reason, the Issuer will nevertheless continue filing the reports specified in the preceding paragraphs of this covenant with the SEC within the time periods specified above unless the SEC will not accept such a filing. The Issuer will not take any action for the purpose of causing the SEC not to accept any such filings. If, notwithstanding the foregoing, the SEC will not accept the Issuer’s filings for any reason, the Issuer will post the reports referred to in the preceding paragraphs on its website within the time periods that would apply if the Issuer were required to file those reports with the SEC.
If the Issuer has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraphs will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of the Issuer and the Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Issuer.
In addition, the Issuer and the Guarantors agree that, for so long as any of the notes remain outstanding, if at any time they are not required to file with the SEC the reports required by the preceding paragraphs, they will furnish to the holders of notes and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.
Events of Default and Remedies
Each of the following is an “Event of Default”:
(1)
default for 30 days in the payment when due of interest on, or Additional Interest, if any, with respect to, the notes;
(2)
default in the payment when due (at maturity, upon redemption or otherwise) of the principal of, or premium, if any, on, the notes;
(3)
failure by the Issuer or any of its Restricted Subsidiaries to comply with the provisions described under the captions “—Repurchase at the Option of Holders—Change of Control,” “—Repurchase at the Option of Holders—Asset Sales,” or “—Certain Covenants—Merger, Consolidation or Sale of Assets;”
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(4)
failure by the Issuer or any of its Restricted Subsidiaries for 60 days after notice to the Issuer by the Trustee or the holders of at least 25% in aggregate principal amount of the notes then outstanding voting as a single class to comply with any of the other agreements in the Indenture;
(5)
default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Issuer or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Issuer or any of its Restricted Subsidiaries), whether such Indebtedness or Guarantee existed as of the Issue Date, or is created after the Issue Date, if that default:
(a)
is caused by a failure to pay principal of, or interest or premium, if any, on, such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a “Payment Default”); or
(b)
results in the acceleration of such Indebtedness prior to its Stated Maturity,
and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $5.0 million or more;
(6)
failure by the Issuer or any of its Restricted Subsidiaries to pay final judgments entered by a court or courts of competent jurisdiction aggregating in excess of $5.0 million, which judgments are not paid, discharged or stayed for a period of 60 days;
(7)
except as permitted by the Indenture, any Note Guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or any Guarantor, or any Person acting on behalf of any Guarantor, denies or disaffirms its obligations under its Note Guarantee;
(8)
(x) any Security Document at any time for any reason shall cease to be in full force and effect in all material respects; (y) any Security Document ceases to give the Collateral Agent the Liens, rights, powers and privileges purported to be created thereby with respect to any Collateral having a Fair Market Value in excess of $1.0 million, superior to and prior to the rights of all third Persons other than the holders of Permitted Liens and subject to no other Liens except as expressly permitted by the applicable Security Document or the Indenture; or (z) the Issuer or any of the Guarantors, directly or indirectly, contests in any manner the effectiveness, validity, binding nature or enforceability of any Security Document; and
(9)
certain events of bankruptcy or insolvency described in the Indenture with respect to the Issuer or any of its Restricted Subsidiaries that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.
In the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to the Issuer, any Restricted Subsidiary of the Issuer that is a Significant Subsidiary or any group of Restricted Subsidiaries of the Issuer that, taken together, would constitute a Significant Subsidiary, all outstanding notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes may declare all the notes to be due and payable immediately.
Subject to certain limitations, holders of a majority in aggregate principal amount of the then outstanding notes may direct the Trustee in its exercise of any trust or power. The Trustee may withhold from holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal, interest or premium or Additional Interest, if any.
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Subject to the provisions of the Indenture and the Security Documents relating to the duties of the Trustee and the Collateral Agent, in case an Event of Default occurs and is continuing, neither the Trustee nor the Collateral Agent will be under any obligation to exercise any of the rights or powers under the Indenture or any Security Document at the request or direction of any holders of notes unless such holders have offered to the Trustee or the Collateral Agent, as the case may be, reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest or Additional Interest if any, when due, no holder of a note may pursue any remedy with respect to the Indenture or the notes unless:
(1)
such holder has previously given the Trustee notice that an Event of Default is continuing;
(2)
holders of at least 25% in aggregate principal amount of the then outstanding notes have requested the Trustee to pursue the remedy;
(3)
such holders have offered the Trustee reasonable security or indemnity against any loss, liability or expense;
(4)
the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and
(5)
holders of a majority in aggregate principal amount of the then outstanding notes have not given the Trustee a direction inconsistent with such request within such 60-day period.
The holders of a majority in aggregate principal amount of the then outstanding notes by notice to the Trustee may, on behalf of the holders of all of the notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under the Indenture except a continuing Default or Event of Default in the payment of interest or premium or Additional Interest, if any, on, or the principal of, the notes.
The Issuer is required to deliver to the Trustee annually a statement regarding compliance with the Indenture. Upon becoming aware of any Default or Event of Default, the Issuer is required to deliver to the Trustee a statement specifying such Default or Event of Default.
No Personal Liability of Directors, Officers, Employees and Stockholders
No director, officer, employee, incorporator or stockholder of the Issuer or any Guarantor, as such, will have any liability for any obligations of the Issuer or the Guarantors under the notes, the Indenture, the Note Guarantees, the Security Documents or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.
Legal Defeasance and Covenant Defeasance
The Issuer may at any time, at the option of its Board of Directors evidenced by a resolution set forth in an Officers’ Certificate, elect to have all of its obligations discharged with respect to the outstanding notes and all obligations of the Guarantors discharged with respect to their Note Guarantees (“Legal Defeasance”) except for:
(1)
the rights of holders of outstanding notes to receive payments in respect of the principal of, or interest or premium and Additional Interest, if any, on, such notes when such payments are due from the trust referred to below;
(2)
the Issuer’s obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;
(3)
the rights, powers, trusts, duties and immunities of the Trustee, and the Issuer’s and the Guarantors’ obligations in connection therewith; and
(4)
the Legal Defeasance and Covenant Defeasance provisions of the Indenture.
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In addition, the Issuer may, at its option and at any time, elect to have the obligations of the Issuer and the Guarantors released with respect to certain covenants (including its obligation to make Change of Control Offers and Asset Sale Offers) that are described in the Indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, receivership, rehabilitation and insolvency events) described under “—Events of Default and Remedies” will no longer constitute an Event of Default with respect to the notes.
In order to exercise either Legal Defeasance or Covenant Defeasance:
(1)
the Issuer must irrevocably deposit with the Trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants, to pay the principal of, or interest and premium and Additional Interest, if any, on, the outstanding notes on the stated date for payment thereof or on the applicable redemption date, as the case may be, and the Issuer must specify whether the notes are being defeased to such stated date for payment or to a particular redemption date;
(2)
in the case of Legal Defeasance, the Issuer must deliver to the Trustee an Opinion of Counsel reasonably acceptable to the Trustee confirming that (a) the Issuer has received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the Issue Date, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such Opinion of Counsel will confirm that, the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;
(3)
in the case of Covenant Defeasance, the Issuer must deliver to the Trustee an Opinion of Counsel reasonably acceptable to the Trustee confirming that the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;
(4)
no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit) and the deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which the Issuer or any Guarantor is a party or by which the Issuer or any Guarantor is bound;
(5)
such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the Indenture) to which the Issuer or any of its Subsidiaries is a party or by which the Issuer or any of its Subsidiaries is bound;
(6)
the Issuer must deliver to the Trustee an Officers’ Certificate stating that the deposit was not made by the Issuer with the intent of preferring the holders of notes over the other creditors of the Issuer with the intent of defeating, hindering, delaying or defrauding any creditors of the Issuer or any Guarantor or others; and
(7)
the Issuer must deliver to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.
Amendment, Supplement and Waiver
Except as provided in the next three succeeding paragraphs, the Indenture or the notes or the Note Guarantees or the Security Documents may be amended or supplemented with the consent of the holders of at least a majority in aggregate principal amount of the notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes), and any existing Default or Event of Default or compliance with any provision of the Indenture or the notes or the Note Guarantees or the Security Documents may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).
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Without the consent of each holder of notes affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting holder):
(1)
reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;
(2)
reduce the principal of or change the fixed maturity of any note or alter the provisions with respect to the redemption of the notes (other than provisions relating to the covenants described above under the caption “—Repurchase at the Option of Holders”);
(3)
reduce the rate of or change the time for payment of interest, including default interest, on any note;
(4)
waive a Default or Event of Default in the payment of principal of, or interest or premium, or Additional Interest, if any, on, the notes (except a rescission of acceleration of the notes by the holders of at least a majority in aggregate principal amount of the then outstanding notes and a waiver of the payment default that resulted from such acceleration);
(5)
make any note payable in money other than that stated in the notes;
(6)
make any change in the provisions of the Indenture relating to waivers of past Defaults or the rights of holders of notes to receive payments of principal of, or interest or premium or Additional Interest, if any, on, the notes;
(7)
waive a redemption payment with respect to any note (other than a payment required by one of the covenants described above under the caption “—Repurchase at the Option of Holders”);
(8)
release any Guarantor from any of its obligations under its Note Guarantee or the Indenture, except in accordance with the terms of the Indenture; or
(9)
make any change in the preceding amendment and waiver provisions.
In addition, any amendment to, or waiver of, the provisions of the Indenture, any Security Document or the Intercreditor Agreement that has the effect of releasing all or substantially all of the Collateral from the Liens securing the notes or subordinating Liens securing the notes (except as permitted by the terms of the Indenture, the Security Documents and the Intercreditor Agreement) will require the consent of the holders of at least 662/3% in aggregate principal amount of the notes then outstanding.
Notwithstanding the preceding, without the consent of any holder of notes, the Issuer, the Guarantors and the Trustee may amend or supplement the Indenture, the notes or the Note Guarantees:
(1)
to cure any ambiguity, defect or inconsistency;
(2)
to provide for uncertificated notes in addition to or in place of certificated notes;
(3)
to provide for the assumption of the Issuer’s or a Guarantor’s obligations to holders of notes and Note Guarantees in the case of a merger or consolidation or sale of all or substantially all of the Issuer’s or such Guarantor’s assets, as applicable;
(4)
to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the Indenture of any such holder;
(5)
to comply with requirements of the SEC in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act;
(6)
to provide for the issuance of additional notes in accordance with the limitations set forth in the Indenture as of the Issue Date;
(7)
to allow any Guarantor to execute a supplemental indenture and/or a Note Guarantee with respect to the notes; or
(8)
to evidence or provide for the acceptance of appointment under the Indenture of a successor trustee.
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The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment, waiver or consent. It is sufficient if such consent approves the substance of the proposed amendment, waiver or consent. The consent of the holders is also not necessary for any amendment, waiver or other modification described in the paragraph under the heading “—Intercreditor Agreement—Amendments to Security Documents.”
Satisfaction and Discharge
The Indenture will be discharged and will cease to be of further effect as to all notes issued thereunder, when:
(1)
either:
(a)
all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to the Issuer, have been delivered to the Trustee for cancellation; or
(b)
all notes that have not been delivered to the Trustee for cancellation have become due and payable by reason of the mailing of a notice of redemption (or delivering such notice of redemption in accordance with the procedures of DTC) or otherwise or will become due and payable within one year and the Issuer or any Guarantor has irrevocably deposited or caused to be deposited with the Trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire Indebtedness on the notes not delivered to the Trustee for cancellation for principal, interest and premium, Additional Interest, if any, and accrued interest to the date of maturity or redemption;
(2)
no Default or Event of Default has occurred and is continuing on the date of the deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit) and the deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which the Issuer or any Guarantor is a party or by which the Issuer or any Guarantor is bound;
(3)
the Issuer or any Guarantor has paid or caused to be paid all sums payable by it under the Indenture; and
(4)
the Issuer has delivered irrevocable instructions to the Trustee under the Indenture to apply the deposited money toward the payment of the notes at maturity or on the redemption date, as the case may be.
In addition, the Issuer must deliver an Officers’ Certificate and an Opinion of Counsel to the Trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.
Concerning the Trustee
If the Trustee becomes a creditor of the Issuer or any Guarantor, the Indenture limits the right of the Trustee to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as Trustee (if the Indenture has been qualified under the Trust Indenture Act) or resign.
The holders of a majority in aggregate principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee, subject to certain exceptions. The Indenture provides that in case an Event of Default occurs and is continuing, the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the Trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any holder of notes, unless such holder has offered to the Trustee security and indemnity satisfactory to it against any loss, liability or expense.
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Governing Law
The Indenture will provide that it, the notes, the Note Guarantees and the Security Documents will be governed by, and construed in accordance with, the laws of the State of New York.
Additional Information
Anyone who receives this prospectus may obtain a copy of the Indenture and registration rights agreement without charge by writing to Saratoga Resources, Inc., 3 Riverway, Suite 1810, Houston, Texas 77056, Attention: Chief Accounting Officer.
Book-Entry, Delivery and Form
The exchange notes will be issued initially only in the form of one or more global notes (collectively, the “Global Notes”). The Global Notes will be deposited upon issuance with the trustee as custodian for The Depository Trust Company (“DTC”), in New York, New York, and registered in the name of DTC’s nominee, Cede & Co., in each case for credit to an account of a direct or indirect participant in DTC as described below. Beneficial interests in the Global Notes may be held through the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”) (as indirect participants in DTC).
The Global Notes may be transferred, in whole but not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for notes in registered, certificated form (“Certificated Notes”) except in the limited circumstances described below. See “— Exchange of Global Notes for Certificated Notes.” Transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.
Depository Procedures
The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes from time to time by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.
DTC has advised us that DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.
DTC has also advised us that, pursuant to procedures established by it:
(1)
upon deposit of the Global Notes, DTC will credit the accounts of Participants designated by the exchange agent with portions of the principal amount of the Global Notes; and
(2)
ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC or its nominee (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in the Global Notes).
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Investors in the Global Notes who are Participants in DTC’s system may hold their interests therein directly through DTC. Investors in the Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants in such system. Euroclear and Clearstream may hold interests in the Global Notes on behalf of their participants through customers’ securities accounts in their respective names on the books of their respective depositories, which are Euroclear Bank S.A./N.V., as operator of Euroclear, and Citibank, N.A., as operator of Clearstream. All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems.
The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.
Except as described below, owners of an interest in the Global Notes will not have notes registered in their names, will not receive physical delivery of Certificated Notes and will not be considered the registered owners or “holders” thereof under the Indenture for any purpose.
Payments in respect of the principal of, and interest and premium (if any) on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the Indenture. Under the terms of the Indenture, the Issuer, the Guarantors and the trustee will treat the Persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Issuer, the Guarantors, the trustee nor any agent of an Issuer or the trustee has or will have any responsibility or liability for:
(1)
any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or
(2)
any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.
DTC has advised us that its current practice, at the due date of any payment in respect of securities such as the notes, is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the notes as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or the Issuer. Neither the Issuer nor the trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the notes, and the Issuer and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.
Transfers of exchange notes between Participants will be effected in accordance with DTC’s procedures and will be settled in same-day funds, and such transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.
Cross-market transfers of exchange notes between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by its depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.
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DTC has advised us that it will take any action permitted to be taken by a holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for Certificated Notes, and to distribute such notes to its Participants.
Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. None of the Issuer, the trustee or any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.
Exchange of Global Notes for Certificated Notes
A Global Note is exchangeable for Certificated Notes in minimum denominations of $2,000 and in integral multiples of $1,000 in excess of $2,000, if:
(1)
DTC (a) notifies the Issuer that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and, in either case, the Issuer fails to appoint a successor depositary within 90 days;
(2)
the Issuer, at its option, notifies the trustee in writing that it elects to cause the issuance of the Certificated Notes; or
(3)
there has occurred and is continuing a Default or Event of Default with respect to the notes.
In addition, beneficial interests in the notes may be exchanged for Certificated Notes upon prior written notice given to the trustee by or on behalf of DTC in accordance with the Indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).
Exchange of Certificated Notes for Global Notes
Certificated Notes may not be exchanged for beneficial interests in any Global Note, except in the limited circumstances provided in the Indenture.
Same Day Settlement and Payment
If a holder has given wire instructions to the Issuer, the Issuer will make payments in respect of the notes represented by the Global Notes (including principal, premium, if any, and interest) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. If a holder has given wire instructions to the Issuer, the Issuer will make all payments of principal, interest and premium, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the holders of the Certificated Notes. All other payments on the notes will be made at the office or agency of the paying agent and registrar unless the Issuer elects to make interest payments by check mailed to the holders at their addresses set forth in the register of holders. The notes represented by the Global Notes are expected to be eligible to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds. The Issuer expects that secondary trading in any Certificated Notes will also be settled in immediately available funds.
Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised us that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.
Certain Definitions
Set forth below are certain defined terms used in the Indenture. Reference is made to the Indenture for a full disclosure of all defined terms used therein, as well as any other capitalized terms used herein for which no definition is provided.
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“Acquired Debt” means, with respect to any specified Person:
(1)
Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, or expressly assumed in connection with the acquisition of assets from any such Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person; and
(2)
Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.
Acquired Debt will be deemed to be incurred on the date the acquired Person becomes a Subsidiary.
“Additional Interest” means all liquidated damages then owing pursuant to the registration rights agreement.
“Additional Notes” means additional notes (other than the Initial Notes) issued under the Indenture in accordance with Sections 2.02 and 4.09 thereof, as part of the same series as the Initial Notes.
“Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination:
(1)
the sum of:
(a)
discounted future net revenue from proved crude oil and natural gas reserves of the Issuer and its Restricted Subsidiaries calculated in accordance with SEC guidelines (but giving effect to applicable Oil and Gas Hedging Contracts in place as of the date of determination (whether positive or negative)) before any state or federal income taxes, as estimated in a reserve report prepared by the Issuer as of the end of the Issuer’s most recently completed fiscal year, as increased by, as of the date of determination, the discounted future net revenue (giving effect to applicable Oil and Gas Hedging Contracts in place as of the date of determination (whether positive or negative)) from:
(i)
estimated proved crude oil and natural gas reserves of the Issuer and its Restricted Subsidiaries attributable to acquisitions consummated since the date of such year-end reserve report, and
(ii)
estimated crude oil and natural gas reserves of the Issuer and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward determinations of estimates of proved crude oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior year end) due to exploration, development or exploitation, production or other activities which reserves were not reflected in such year-end reserve report,
in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report), and decreased by, as of the date of determination, the discounted future net revenue attributable to
(iii)
estimated proved crude oil and natural gas reserves of the Issuer and its Restricted Subsidiaries reflected in such year-end reserve report produced or disposed of since the date of such year-end reserve report and
(iv)
reductions in the estimated proved crude oil and natural gas reserves of the Issuer and its Restricted Subsidiaries reflected in such year-end reserve report since the date of such year-end reserve report attributable to downward determinations of estimates of proved crude oil and natural gas reserves due to exploration, development or exploitation, production or other activities conducted or otherwise occurring since the date of such year-end reserve report, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report);
provided, however, that in the case of each of the determinations made pursuant to clauses (i) through (iv), such increases and decreases shall be as estimated by the Issuer’s petroleum engineers, unless there is a Material Change as a result of such acquisitions, dispositions or revisions, in which case the discounted future net revenues utilized for purposes of this clause 1(a) shall be confirmed in a written report of independent petroleum engineers delivered to the Trustee.
(b)
the capitalized costs that are attributable to crude oil and natural gas properties of the Issuer and its Restricted Subsidiaries to which no proved crude oil and natural gas reserves are attributed, based on the Issuer’s books and records as of a date no earlier than the date of the Issuer’s latest annual or quarterly financial statements; provided that the aggregate value of the capitalized costs included pursuant to this clause (b) and the tangible assets included pursuant to clause (d) of this definition shall not exceed $80.0 million;
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(c)
the Net Working Capital on a date no earlier than the date of the Issuer’s latest annual or quarterly financial statements; and
(d)
the greater of (I) the net book value on a date no earlier than the date of the Issuer’s latest annual or quarterly financial statements and (II) the appraised value, as estimated by independent appraisers, of other tangible assets of the Issuer and its Restricted Subsidiaries as of a date no earlier than the date of the Issuer’s latest audited financial statements; provided that if no such appraisal has been performed, the Issuer shall not be required to obtain such an appraisal and only clause (d)(I) of this definition shall apply; provided further that the aggregate value of the tangible assets included pursuant to this clause (d) and the capitalized costs included pursuant to clause (b) of this definition shall not exceed $80.0 million; provided further that this clause (d) shall exclude any value of the tangible assets included pursuant to clause (a) of this definition including, but not limited to, any reduction in operating costs that is included in the Issuer’s present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual discount rate of 10%;
(2)
minus, to the extent not otherwise taken into account in the immediately preceding clause (1), the sum of:
(a)
minority interests;
(b)
any net gas balancing liabilities of the Issuer and its Restricted Subsidiaries reflected in the Issuer’s latest audited financial statements or the Issuer’s most recent quarterly balance sheet if it reflects greater gas balancing liabilities;
(c)
the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Issuer’s year-end reserve report), attributable to reserves subject to participation interests, overriding royalty interests or other interests of third parties, pursuant to participation, partnership, vendor financing or other agreements then in effect, or which otherwise are required to be delivered to third parties;
(d)
the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Issuer’s year-end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of the Issuer and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto; and
(e)
the discounted future net revenue, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production included in determining the discounted future net revenue specified in the immediately preceding clause (1)(a) (utilizing the same prices utilized in the Issuer’s year-end reserve report), would be necessary to satisfy fully the obligations of the Issuer and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.
“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; provided that beneficial ownership of 10% or more of the Voting Stock of a Person will be deemed to be control. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.
“Asset Sale” means:
(1)
the sale, lease (other than operating leases entered into in the ordinary course of business), conveyance or other disposition of any assets or rights, including Production Payments and Reserve Sales; provided that the sale, lease, conveyance or other disposition of all or substantially all of the assets of the Issuer and its Restricted Subsidiaries taken as a whole will be governed by the provisions described above under the caption “—Repurchase at the Option of Holders—Change of Control” and/or the provisions described above under the caption “—Certain Covenants –Merger, Consolidation or Sale of Assets and not by the provisions of the Asset Sale covenant; and
(2)
the issuance of Equity Interests in any of the Issuer’s Restricted Subsidiaries or the sale of Equity Interests in any of the Issuer’s Restricted Subsidiaries.
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Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:
(1)
any single transaction or series of related transactions that involves assets having a Fair Market Value of less than $1.0 million;
(2)
a transfer of assets between or among the Issuer and its Restricted Subsidiaries;
(3)
an issuance of Equity Interests by a Restricted Subsidiary of the Issuer to the Issuer or to a Restricted Subsidiary of the Issuer;
(4)
the sale or lease of products, services or accounts receivable in the ordinary course of business and any sale or other disposition of damaged, no longer useful, worn-out or obsolete assets in the ordinary course of business;
(5)
the sale or other disposition of cash or Cash Equivalents;
(6)
the surrender or waiver of contract rights, oil and gas leases or the settlement, release or surrender of contract, tort or other claims of any kind;
(7)
the abandonment, farm-out, lease or sublease of developed or undeveloped Oil and Gas Properties in the ordinary course of business;
(8)
any Production Payment and Reserve Sale, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Issuer or a Restricted Subsidiary, created, issued or assumed in connection with the financing of the acquisition of oil and gas properties that are subject thereto (and within 90 days after such acquisition), so long as the owner or purchaser of such Production Payment and Reserve Sale has recourse solely to such oil and gas properties and to the proceeds thereof, subject to the obligation of the grantor or transferor of such Production Payment and Reserve Sale to operate and maintain the related oil and gas properties in a prudent manner or other customary standard, to deliver the associated production (if required) and to indemnify with respect to environmental, title and other matters customary in the Oil and Gas Business;
(9)
the sale or transfer (whether or not in the ordinary course of business) of any Oil and Gas Property or interest therein to which no proved or probable reserves are attributable at the time of such sale or transfer;
(10)
the sale or transfer of Hydrocarbons or other mineral products in the ordinary course of business;
(11)
any trade or exchange by the Issuer or any Restricted Subsidiary of Oil and Gas Properties or other properties or assets for Oil and Gas Properties or other properties or assets owned or held by another Person; provided that the Fair Market Value of the properties or assets traded or exchanged by the Issuer or such Restricted Subsidiary (together with any cash) is reasonably equivalent to the Fair Market Value of the properties or assets (together with any cash) to be received by the Issuer or such Restricted Subsidiary; provided further that any net cash received must be applied in accordance with the provisions described above under the caption “—Repurchase at the Option of Holders—Asset Sales;” and
(12)
any Restricted Payment that does not violate the covenant described above under the caption “—Certain Covenants—Restricted Payments” or a Permitted Investment.
“Bankruptcy Law” means Title 11, U.S. Code or any similar federal or state law for the relief of debtors.
“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular ‘‘person’’ (as that term is used in Section 13(d)(3) of the Exchange Act), such ‘‘person’’ will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.
“Board of Directors” means:
(1)
with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;
(2)
with respect to a partnership, the board of directors of the general partner of the partnership;
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(3)
with respect to a limited liability company, the managing member or members or any controlling committee of managing members thereof; and
(4)
with respect to any other Person, the board or committee of such Person serving a similar function.
“Business Day” means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York are authorized or required by law to close.
“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet prepared in accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty.
“Capital Stock” means:
(1)
in the case of a corporation, corporate stock;
(2)
in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;
(3)
in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and
(4)
any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.
“Cash Equivalents” means:
(1)
United States dollars;
(2)
securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than six months from the date of acquisition;
(3)
certificates of deposit and eurodollar time deposits with maturities of six months or less from the date of acquisition, bankers’ acceptances with maturities not exceeding six months and overnight bank deposits, in each case, with any domestic commercial bank having capital and surplus in excess of $500.0 million and a Thomson Bank Watch Rating of “B” or better;
(4)
repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;
(5)
commercial paper having one of the two highest ratings obtainable from Moody’s or S&P and, in each case, maturing within six months after the date of acquisition; and
(6)
money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition.
“Change of Control” means the occurrence of any of the following:
(1)
the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Issuer and its Subsidiaries taken as a whole to any “person” (as that term is used in Section 13(d) of the Exchange Act);
(2)
the adoption of a plan relating to the liquidation or dissolution of the Issuer;
(3)
the consummation of any transaction (including, without limitation, any merger or consolidation), the result of which is that any “person” (as defined above) becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Issuer, measured by voting power rather than number of shares;
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(4)
the Issuer consolidates with, or merges with or into, any Person, or any Person consolidates with, or merges with or into, the Issuer, in any such event pursuant to a transaction in which any of the outstanding Voting Stock of the Issuer or such other Person is converted into or exchanged for cash, securities or other property, other than any such transaction where the Voting Stock of the Issuer outstanding immediately prior to such transaction is converted into or exchanged for Voting Stock (other than Disqualified Stock) of the surviving or transferee Person constituting a majority of the outstanding shares of such Voting Stock of such surviving or transferee Person (immediately after giving effect to such issuance); or
(5)
the first day on which a majority of the members of the Board of Directors of the Issuer are not Continuing Directors.
“Collateral” means collateral as such term is defined in the Security Agreement, and any other property, whether now owned or hereafter acquired, upon which a Lien securing the Obligations under the Indenture, the Security Documents, the Notes or the Note Guarantees is granted under any Security Document; provided, however, that “Collateral” shall not include any Excluded Assets.
“Collateral Agent” means The Bank of New York Mellon Trust Company, N.A., acting in its capacity as the collateral agent for the Holders until a successor replaces it in accordance with the provisions of the Indenture and thereafter means any such successor.
“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus, without duplication:
(1)
an amount equal to any extraordinary loss plus any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale, to the extent such losses were deducted in computing such Consolidated Net Income; plus
(2)
provision for federal taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for federal taxes was deducted in computing such Consolidated Net Income; plus
(3)
the Fixed Charges of such Person and its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income; plus
(4)
depreciation, amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period) and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, amortization and other non-cash expenses were deducted in computing such Consolidated Net Income; minus
(5)
non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue in the ordinary course of business;
in each case, on a consolidated basis and determined in accordance with GAAP.
“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:
(1)
the Net Income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included only to the extent of the amount of dividends or similar distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;
(2)
the Net Income of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders;
(3)
the cumulative effect of a change in accounting principles will be excluded;
(4)
any “ceiling limitation” on oil and gas properties or other asset impairment write-downs under GAAP or SEC guidelines will be excluded; and
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(5)
notwithstanding clause (1) above, the Net Income of any Unrestricted Subsidiary will be excluded, whether or not distributed to the specified Person or one of its Subsidiaries.
“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Issuer who:
(1)
was a member of such Board of Directors on the Issue Date; or
(2)
was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election.
“Credit Facilities” means, one or more debt facilities or agreements (including without limitation the Indenture) or commercial paper facilities, in each case, with banks or other institutional lenders, commercial finance companies, creditors, investors or other lenders providing for revolving credit loans, term loans, bonds, debentures, hedging, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, pursuant to agreements or indentures, in each case, as amended, restated, modified, renewed, refunded, replaced (whether upon or after termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time (and without limitation as to amount, terms, conditions, covenants and other provisions, including increasing the amount of available borrowings thereunder, changing or replacing agent banks and lenders thereunder or adding, removing or reclassifying Subsidiaries of the Issuer as borrowers or guarantors thereunder).
“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.
“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case, at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the Notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require the Issuer to repurchase such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that the Issuer may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The amount of Disqualified Stock deemed to be outstanding at any time for purposes of the Indenture will be the maximum amount that the Issuer and its Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.
“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.
“Domestic Subsidiary” means any Restricted Subsidiary of the Issuer that was formed under the laws of the United States or any state of the United States or the District of Columbia or that guarantees or otherwise provides direct credit support for any Indebtedness of the Issuer.
“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).
“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.
“Existing Indebtedness” means all Indebtedness of the Issuer and its Subsidiaries (other than Indebtedness under the Notes and the Note Guarantees in existence on the Issue Date) until such amounts are repaid.
“Fair Market Value” means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors of the Issuer (unless otherwise provided in the Indenture).
“First Lien Creditors” means the Trustee, the Collateral Agent, each Holder, the beneficiaries of each indemnification obligation under the Indenture, the Notes and the Security Documents, and any successor or transferee of any of the foregoing.
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“First Lien Documents” means (a) the Indenture, the Notes, the Note Guarantees, the Security Documents and each of the other agreements, documents or instruments under any Credit Facility evidencing or governing any First Lien Obligations and (b) any other related documents or instruments executed and delivered pursuant to any First Lien Document described in clause (a) above evidencing or governing any First Lien Obligations thereunder, in each case, as amended, restated, modified, renewed, refunded, replaced (whether upon termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.
“First Lien Obligations” means all Obligations in respect of the Notes or arising under the First Lien Documents or any of them. First Lien Obligations shall include all interest accrued (or which would, absent the commencement of an insolvency or liquidation proceeding, accrue) after the commencement of an insolvency or liquidation proceeding in accordance with and at the rate specified in the relevant First Lien Document whether or not the claim for such interest is allowed as a claim in such insolvency or liquidation proceeding (including all amounts accruing on or after the commencement of an insolvency proceeding, or that would have accrued or become due but for the effect of an insolvency proceeding and irrespective of whether a claim for all or any portion of such amounts is allowable or allowed in such insolvency proceeding).
“Fixed Charge Coverage Ratio” means with respect to any specified Person for any period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period.
In addition, for purposes of calculating the Fixed Charge Coverage Ratio:
(1)
acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations, or any Person or any of its Restricted Subsidiaries acquired by the specified Person or any of its Restricted Subsidiaries, and including any related financing transactions and including increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date will be given pro forma effect (in accordance with Regulation S-X under the Securities Act) as if they had occurred on the first day of the four-quarter reference period;
(2)
the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded;
(3)
the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;
(4)
any Person that is a Restricted Subsidiary on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period;
(5)
any Person that is not a Restricted Subsidiary on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period; and
(6)
if any Indebtedness bears a floating rate of interest, the interest expense on such Indebtedness will be calculated as if the rate in effect on the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligation applicable to such Indebtedness if such Hedging Obligation has a remaining term as at the Calculation Date in excess of 12 months).
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“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:
(1)
the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued, including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings, and net of the effect of all payments made or received pursuant to Hedging Obligations in respect of interest rates; plus
(2)
the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus
(3)
any interest on Indebtedness of another Person that is guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such Guarantee or Lien is called upon; plus
(4)
the product of (a) all dividends, whether paid or accrued and whether or not in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of the Issuer (other than Disqualified Stock) or to the Issuer or a Restricted Subsidiary of the Issuer, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state and local statutory tax rate of such Person, expressed as a decimal, in each case, determined on a consolidated basis in accordance with GAAP.
“Foreign Subsidiary” means any Restricted Subsidiary of the Issuer that is not a Domestic Subsidiary.
“GAAP” means generally accepted accounting principles in the United States, which are in effect from time to time.
“Government Securities” means securities that are:
(1)
direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged, or
(2)
obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America,
which, in either case, are not callable or redeemable at the option of the issuers thereof, and shall also include a depository receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such Government Securities or a specific payment of principal of or interest on any such Government Securities held by such custodian for the account of the holder of such depository receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the Government Securities or the specific payment of principal of or interest on the Government Securities evidenced by such depository receipt.
“Guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness. When used as a verb, “guarantee” has a correlative meaning.
“Guarantors” means (1) each Domestic Subsidiary of the Issuer on the Issue Date and any other Subsidiary of the Issuer that Guarantees the First Lien Notes and (2) each other Domestic Subsidiary of the Issuer that executes a Note Guarantee in accordance with the provisions of the Indenture, in each case, together with their respective successors and assigns until the Note Guarantee of such Person has been released in accordance with the provisions of the Indenture.
“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person under:
(1)
interest rate swap agreements (whether from fixed to floating or from floating to fixed), interest rate cap agreements and interest rate collar agreements;
(2)
other agreements or arrangements designed to manage interest rates or interest rate risk; and
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(3)
other agreements or arrangements designed to protect such Person against fluctuations in currency exchange rates or commodity prices.
in each case, not entered into for speculative purposes.
“Holder” means a Person in whose name a note is registered.
“Hydrocarbon Interests” means all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.
“Hydrocarbons” means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.
“Indebtedness” means, with respect to any specified Person:
(1)
any indebtedness of such Person (excluding accrued expenses and trade payables), whether or not contingent:
(a)
in respect of borrowed money;
(b)
evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);
(c)
in respect of banker’s acceptances;
(d)
representing Capital Lease Obligations;
(e)
representing the balance deferred and unpaid of the purchase price of any property or services due more than six months after such property is acquired or such services are completed; or
(f)
representing any Hedging Obligations; and
(2)
with respect to any Production Payment, any warranties or guarantees of production or payment by such Person with respect to such Production Payment but excluding other contractual obligations of such Person with respect to such Production Payment;
in each case, if and to the extent any of the preceding items (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) and, to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person. Subject to clause (b) of this definition, Production Payments shall not be deemed to be Indebtedness.
“Initial Notes” means the first $54.6 million aggregate principal amount of Notes issued under the Indenture on the Issue Date, and any notes issued upon registration of transfer thereof or in exchange therefor.
“Intercreditor Agreement” means the intercreditor agreement entered into on the Issue Date, among the Trustee, in its capacity as Trustee and Collateral Agent, the trustee under the Second Lien Documents, the Issuer and the Guarantors and the other signatories thereto, as the same may be amended, supplemented, restated or modified from time to time.
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“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If the Issuer or any Subsidiary of the Issuer sells or otherwise disposes of any Equity Interests of any direct or indirect Subsidiary of the Issuer such that, after giving effect to any such sale or disposition, such Person is no longer a Subsidiary of the Issuer, the Issuer will be deemed to have made an Investment on the date of any such sale or disposition equal to the Fair Market Value of the Issuer’s Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The acquisition by the Issuer or any Subsidiary of the Issuer of a Person that holds an Investment in a third Person will be deemed to be an Investment by the Issuer or such Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investments held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption”—Certain Covenants—Restricted Payments.” Except as otherwise provided in the Indenture, the amount of an Investment will be determined at the time the Investment is made and without giving effect to subsequent changes in value.
“Issue Date” means November 22, 2013, the date of the original issuance of the notes.
“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction.
“Material Change” means an increase or decrease (excluding changes that result solely from changes in prices) of more than 25% during a fiscal quarter in the estimated discounted future net cash flows from proved oil and gas reserves of the Issuer and its Restricted Subsidiaries, calculated in accordance with the first clause (a) of the definition of Adjusted Consolidated Net Tangible Assets; provided, however, that there will be excluded from the calculation of Material Change the estimated future net cash flows from:
(1)
any acquisitions during the fiscal quarter of oil and gas reserves that have been audited by a nationally recognized firm of independent petroleum engineers and on which a report or reports exist; and
(2)
any disposition of properties held at the beginning of such quarter that have been disposed of as provided the Section entitled “Asset Sales.”
“Moody’s” means Moody’s Investors Service, Inc. or any successor to the rating agency business thereof.
“Mortgages” means the mortgages, deeds of trust, deeds to secure Indebtedness or other similar documents granting Liens on the Issuer’s and the Restricted Subsidiaries’ properties and interests, Premises and/or the Leased Premises to secure the notes.
“Net Income” means, with respect to any specified Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however:
(1)
any gain (but not loss), together with any related provision for taxes on such gain (but not loss), realized in connection with: (a) any Asset Sale; or (b) the disposition of any securities by such Person or any of its Restricted Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Restricted Subsidiaries; and
(2)
any extraordinary gain (but not loss), together with any related provision for taxes on such extraordinary gain (but not loss).
“Net Proceeds” means the aggregate cash proceeds received by the Issuer or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale, taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements, secured by a Lien on the asset or assets that were the subject of such Asset Sale and any reserve for adjustment in respect of the sale price of such asset or assets established in accordance with GAAP.
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“Net Working Capital” means:
(1)
all current assets of the Issuer and its Restricted Subsidiaries, minus
(2)
all current liabilities of the Issuer and its Restricted Subsidiaries, except current liabilities included in Indebtedness;
in each case, on a consolidated basis and determined in accordance with GAAP.
“Non-Recourse Debt” means Indebtedness:
(1)
as to which neither the Issuer nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) constitutes the lender;
(2)
no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness of the Issuer or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its Stated Maturity; and
(3)
as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of the Issuer or any of its Restricted Subsidiaries.
“Note Guarantee” means the Guarantee by each Guarantor of the Issuer’s Obligations under the Indenture and the notes, executed pursuant to the provisions of the Indenture.
“notes” means the Initial Notes and any Additional Notes issued hereunder. The Initial Notes and any Additional Notes shall be treated as a single class for all purposes under the Indenture, and unless the context otherwise requires, all references to “notes” shall include the Initial Notes and any Additional Notes.
“Obligations” means any principal, interest (including any interest accruing subsequent to the filing of a petition in bankruptcy, reorganization or similar proceeding at the rate provided for in the documentation with respect thereto, whether or not such interest is an allowed claim under applicable state, federal or foreign law), penalties, fees, indemnifications, reimbursements (including, without limitation, reimbursement obligations with respect to letters of credit and banker’s acceptances), damages and other liabilities, and guarantees of payment of such principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities, payable under the documentation governing any Indebtedness.
“Officers’ Certificate” means a certificate signed on behalf of the Issuer by two Officers of the Issuer in their capacities as such and not in their individual capacities, one of whom must be the principal executive officer, the principal financial officer, the treasurer or the principal accounting officer of the Issuer that meets the requirements set forth in the Indenture.
“Oil and Gas Business” means:
(1)
the acquisition, exploration, development, operation and disposition of interests in oil, natural gas and other hydrocarbon properties;
(2)
the gathering, marketing, treating, processing (but not refining), storage, selling and transporting of any production from those interests, including any hedging activities related thereto; and
(3)
any activity necessary, appropriate, incidental or reasonably related to the activities described above.
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“Oil and Gas Properties” means (a) Hydrocarbon Interests, including with respect to undeveloped Oil and Gas Properties, depths below which any proved reserves are then attributable; (b) the Properties now or hereafter pooled or unitized with Hydrocarbon Interests; (c) all presently existing or future unitization, pooling agreements and declarations of pooled units and the units created thereby (including without limitation all units created under orders, regulations and rules of any Governmental Authority) which may affect all or any portion of the Hydrocarbon Interests; (d) all operating agreements, contracts and other agreements, including production sharing contracts and agreements, which relate to any of the Hydrocarbon Interests or the production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to such Hydrocarbon Interests; (e) all Hydrocarbons in and under and which may be produced and saved or attributable to the Hydrocarbon Interests, including all oil in tanks, and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests; (f) all tenements, hereditaments, appurtenances and Properties in any manner appertaining, belonging, affixed or incidental to the Hydrocarbon Interests and (g) all Properties, rights, titles, interests and estates described or referred to above, including any and all Property, real or personal, now owned or hereinafter acquired and situated upon, used, held for use or useful in connection with the operating, working or development of any of such Hydrocarbon Interests or Property (excluding drilling rigs, automotive equipment, rental equipment or other personal Property which may be on such premises for the purpose of drilling a well or for other similar temporary uses) and including any and all oil wells, gas wells, injection wells or other wells, buildings, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping units, field gathering systems, tanks and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, casing, tubing and rods, surface leases, rights-of-way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing.
“Opinion of Counsel” means an opinion reasonably acceptable to the Trustee that meets the requirements of the Indenture. The opinion must be from legal counsel who may be an employee of or counsel to the Issuer or any Subsidiary of the Issuer.
“Other Pari Passu Obligations” means any Indebtedness (i) ranking pari passu in right of payment with the notes, (ii) not secured by any Lien on the Collateral that ranks senior in priority to any Lien on the Collateral held by the Collateral Agent for the benefit of the First Lien Creditors and (iii) containing provisions similar to those set forth in the Indenture with respect to offers to purchase, prepay or redeem with the proceeds of sales of assets.
“Permitted Business Investments” means Investments made in the ordinary course of, and of a nature that is customary in, the Oil and Gas Business, including through agreements, transactions, interests or arrangements that permit one to share risk or costs, or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including without limitation:
(1)
direct or indirect ownership of crude oil, natural gas, other related hydrocarbon and mineral properties or any interest therein or gathering, transportation, processing (but not refining), storage or related systems; and
(2)
the entry into operating agreements, joint ventures, processing agreements, working interests, royalty interests, mineral leases, farm-in agreements, farm-out agreements, development agreements, production sharing agreements, area of mutual interest agreements, contracts for the sale, transportation or exchange of crude oil and natural gas and related hydrocarbons and minerals, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, partnership agreements (whether general or limited), or other similar or customary agreements, transactions, properties, interests or arrangements and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Oil and Gas Business, excluding, however, investments in corporation and publicly-traded partnerships;
provided that no such Permitted Business Investments shall be speculative in nature ..
“Permitted Investments” means:
(1)
any Investment in the Issuer or in a Restricted Subsidiary of the Issuer that is a Guarantor;
(2)
any Investment in Cash Equivalents;
(3)
any Investment by the Issuer or any Restricted Subsidiary of the Issuer in a Person whose primary business is the Oil and Gas Business, if as a result of such Investment:
(a)
such Person becomes a Restricted Subsidiary of the Issuer and a Guarantor; or
(b)
such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Issuer or a Restricted Subsidiary of the Issuer that is a Guarantor;
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(4)
any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales;” provided that such Investments shall be pledged as Collateral to the extent the assets subject to such Asset Sale constituted Collateral;
(5)
any acquisition of assets or Capital Stock solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Issuer;
(6)
any Investments received in compromise or resolution of (A) obligations of trade creditors or customers that were incurred in the ordinary course of business of the Issuer or any of its Restricted Subsidiaries, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; or (B) litigation, arbitration or other disputes with Persons;
(7)
Investments represented by Hedging Obligations;
(8)
loans or advances to employees made in the ordinary course of business of the Issuer or any Restricted Subsidiary of the Issuer in an aggregate principal amount not to exceed $1.0 million at any one time outstanding;
(9)
repurchases of the notes;
(10)
Permitted Business Investments; and
(11)
other Investments in any Person having an aggregate Fair Market Value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (11) that are at the time outstanding not to exceed $5.0 million.
“Permitted Liens” means:
(1)
Liens on assets of the Issuer or any Guarantor securing Indebtedness and other Obligations, in each case incurred under Credit Facilities, that was permitted by the terms of the Indenture to be incurred and/or securing Hedging Obligations related thereto or permitted thereunder;
(2)
Liens in favor of the Issuer or the Guarantors;
(3)
Liens on property of a Person existing at the time such Person is merged with or into or consolidated with the Issuer or any Restricted Subsidiary of the Issuer; provided that such Liens were in existence prior to the contemplation of such merger or consolidation and do not extend to any assets other than those of the Person merged into or consolidated with the Issuer or such Restricted Subsidiary;
(4)
Liens on property (including Capital Stock) existing at the time of acquisition of the property by the Issuer or any Restricted Subsidiary of the Issuer; provided that such Liens were in existence prior to, such acquisition, and not incurred in contemplation of, such acquisition;
(5)
Liens to secure (a) the performance of statutory obligations, surety or appeal bonds, performance bonds, letters of credit or (b) other obligations of a like nature incurred in the ordinary course of business;
(6)
Liens to secure Indebtedness (including Capital Lease Obligations) permitted by clause (4) of the second paragraph of the covenant entitled “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” covering only the assets acquired with or financed by such Indebtedness; provided, however, such Liens are created within 180 days of the later of the acquisition, lease, completion of improvements, construction, repairs or additions or commencement of full operation of the assets or property subject to such Lien and do not encumber any other assets or property of the Issuer or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;
(7)
Liens existing on the Issue Date after giving effect to the exchange of $27.3 million of Second Lien Notes;
(8)
Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings promptly instituted and diligently concluded; provided that any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor;
(9)
Liens imposed by law, such as carriers’, warehousemen’s, landlord’s and mechanics’ Liens, in each case, incurred in the ordinary course of business;
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(10)
survey exceptions, easements or reservations of, or rights of others for, licenses, rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning or other restrictions as to the use of real property that were not incurred in connection with Indebtedness and that do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;
(11)
Liens created for the benefit of (or to secure) the notes (or the Note Guarantees), including for the sake of clarity, any Additional Notes permitted under the Indenture;
(12)
Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the Indenture; provided, however, that:
(a)
the new Lien shall be limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and
(b)
the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (x) the outstanding principal amount, or, if greater, committed amount, of the Permitted Refinancing Indebtedness and (y) an amount necessary to pay any fees and expenses, including premiums, related to such renewal, refunding, refinancing, replacement, defeasance or discharge;
(13)
provisions with respect to the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, stock sale agreements, agreements respecting Permitted Business Investments and other similar agreements entered into in the ordinary course of business;
(14)
Liens on cash or other deposits or net worth imposed by (a) customers under contracts entered into in the ordinary course of business and (b) banks or other depositary institutions on accounts held at such bank or depositary institution;
(15)
Liens arising under oil and gas leases or subleases, assignments, farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, licenses, sublicenses, and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;
(16)
Liens on pipelines and pipeline facilities that arise by operation of law; and
(17)
Liens incurred in the ordinary course of business of the Issuer or any Restricted Subsidiary of the Issuer with respect to obligations that do not exceed $5.0 million at any one time outstanding.
“Permitted Refinancing Indebtedness” means any Indebtedness of the Issuer or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge other Indebtedness of the Issuer or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:
(1)
the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness renewed, refunded, refinanced, replaced, defeased or discharged (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith);
(2)
such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged;
(3)
if the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged is subordinated in right of payment to the Notes, such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and is subordinated in right of payment to, the Notes on terms at least as favorable to Holders as those contained in the documentation governing the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged; and
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(4)
such Indebtedness is incurred either by the Issuer or by the Restricted Subsidiary who is the obligor on the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged.
“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.
“Production Payments” means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments.
“Production Payments and Reserve Sales” means the grant or transfer by the Issuer or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar-denominated), partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Issuer or a Restricted Subsidiary.
“Property” means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including, without limitation, cash, securities, accounts and contract rights.
“Restricted Investment” means an Investment other than a Permitted Investment.
“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.
“S&P” means Standard & Poor’s Ratings Group or any successor to the rating agency business thereof.
“SEC” means the U.S. Securities and Exchange Commission.
“Second Lien Agent” means the trustee or collateral agent under the Second Lien Documents, and any of its respective successors or assigns and any initial or successor administrative agent or collateral agent under any subsequent Second Lien Documents.
“Second Lien Documents” means (a) the Second Lien Indenture, the Second Lien Notes, the Second Lien Note Guarantees, the Second Lien Security Documents and each of the other agreements, documents or instruments evidencing or governing any Second Lien Obligations and (b) any other related documents or instruments executed and delivered pursuant to any Second Lien Document described in clause (a) above evidencing or governing any Obligations thereunder, in each case, as amended, restated, modified, renewed, refunded, replaced (whether upon or after termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.
“Second Lien Indenture” means that certain Indenture, dated as of June 12, 2011, by and among the Issuer, the Guarantors and the Second Lien Agent, as supplemented by that First Supplemental Indenture, dated as of December 4, 2012.
“Second Lien Notes” means “Notes” as defined in the Second Lien Indenture.
“Second Lien Note Guarantees” means the Guarantee by each Guarantor of the Issuer’s Second Lien Obligations under the Second Lien Indenture and the Second Lien Notes, executed pursuant to the provisions of the Second Lien Indenture.
“Second Lien Obligations” means all Obligations (as defined in the Second Lien Indenture) in respect of the Second Lien Notes or arising under the Second Lien Documents or any of them. Second Lien Obligations shall include all interest accrued (or which would, absent the commencement of an insolvency or liquidation proceeding, accrue) after the commencement of an insolvency or liquidation proceeding in accordance with and at the rate specified in the relevant Second Lien Document whether or not the claim for such interest is allowed as a claim in such insolvency or liquidation proceeding (including all amounts accruing on or after the commencement of an insolvency proceeding, or that would have accrued or become due but for the effect of an insolvency proceeding and irrespective of whether a claim for all or any portion of such amounts is allowable or allowed in such insolvency proceeding).
“Second Lien Security Agreement” means the security agreement, dated as of July 12, 2011, between the Second Lien Agent, the Issuer and the Guarantors in favor of the Second Lien Agent, as amended, modified, restated, supplemented or replaced from time to time in accordance with its terms.
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“Second Lien Security Documents” means the Second Lien Security Agreement and each other security agreements, pledge agreements, mortgages, deeds of trust, deeds to secure debt, collateral assignments, control agreements, the Intercreditor Agreement and related agreements (including, without limitation, financing statements under the Uniform Commercial Code of the relevant states), as amended, supplemented, restated, renewed, refunded, replaced, restructured, repaid, refinanced or otherwise modified from time to time, to secure any Second Lien Obligations or under which rights or remedies with respect to any such Lien are governed.
“Securities Act” means the Securities Act of 1933, as amended, and the rules and regulations of the SEC promulgated thereunder.
“Security Agreement” means the security agreement dated as of the Issue Date between the Collateral Agent, the Issuer and the Guarantors, as amended, modified, restated, supplemented or replaced from time to time in accordance with its terms.
“Security Documents” means the security agreements, pledge agreements, mortgages, deeds of trust, deeds to secure debt, collateral assignments, control agreements, the Intercreditor Agreement and related agreements (including, without limitation, financing statements under the Uniform Commercial Code of the relevant states), as amended, supplemented, restated, renewed, refunded, replaced, restructured, repaid, refinanced or otherwise modified from time to time, to secure any First Lien Obligations or under which rights or remedies with respect to any such Lien are governed.
“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the Issue Date.
“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the documentation governing such Indebtedness as of the Issue Date, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.
“Subsidiary” means, with respect to any specified Person:
(1)
any corporation, association or other business entity of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency and after giving effect to any voting agreement or stockholders’ agreement that effectively transfers voting power) to vote in the election of directors, managers or trustees of the corporation, association or other business entity is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and
(2)
any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof);
provided that associations, joint ventures or other relationships (a) which are established pursuant to a standard form operating agreement or similar agreement or which are partnerships for purposes of federal income taxation only, (b) which are not corporations or partnerships (or subject to the Uniform Partnership Act) under applicable state law and (c) whose businesses are limited to the exploration, development and operation of Oil and Gas Properties and interests owned directly by the parties in such associations, joint ventures or relationships, shall not be deemed to be “Subsidiaries” of such Person.
“Trustee” means The Bank of New York Mellon Trust Company, N.A. until a successor replaces it in accordance with the applicable provisions of the Indenture and thereafter means the successor serving hereunder.
“Uniform Commercial Code” or “UCC” means the Uniform Commercial Code as in effect in the relevant jurisdiction from time to time.
“Unrestricted Subsidiary” means any Subsidiary of the Issuer that is designated by the Board of Directors of the Issuer as an Unrestricted Subsidiary pursuant to a resolution of the Board of Directors, but only to the extent that such Subsidiary:
(1)
has no Indebtedness other than Non-Recourse Debt;
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(2)
except as permitted by the covenant described above under the caption “—Certain Covenants—Transactions with Affiliates,” is not party to any agreement, contract, arrangement or understanding with the Issuer or any Restricted Subsidiary of the Issuer unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Issuer or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Issuer;
(3)
is a Person with respect to which neither the Issuer nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and
(4)
has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of the Issuer or any of its Restricted Subsidiaries.
“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.
“Voting Stock” of any specified Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.
“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing: (1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by (2) the then outstanding principal amount of such Indebtedness.
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MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS
Scope of Discussion
The following discussion summarizes the material U.S. federal income and estate tax considerations relating to the exchange of outstanding notes for exchange notes and the ownership and disposition of the exchange notes. This discussion is based upon the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations promulgated under the Code, court decisions, published positions of the Internal Revenue Service (the “IRS”) and other applicable authorities, all as in effect on the date of this prospectus and all of which are subject to change or differing interpretations, possibly with retroactive effect. This discussion is limited to holders of the outstanding notes who acquired their outstanding notes in the initial offering at their “issue price” (i.e., the first price at which a substantial amount of the outstanding notes is sold for cash to persons other than bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers), exchange their outstanding notes for exchange notes, and hold the outstanding notes and exchange notes as “capital assets” within the meaning of Section 1221 of the Code. For purposes of this discussion, “holder” means either a U.S. Holder or a Non-U.S. Holder (each as defined below) or both, as the context may require.
This discussion does not address all of the U.S. federal income tax consequences that may be relevant to holders in light of their particular circumstances or to holders who may be subject to special treatment under U.S. federal income tax laws, such as:
| • |
| financial institutions (including banks); |
| • |
| tax-exempt organizations; |
| • |
| S corporations, entities or arrangements treated as partnerships or any other pass-through entities for U.S. federal income tax purposes; |
| • |
| insurance companies; |
| • |
| mutual funds; |
| • |
| dealers in stocks and securities, or foreign currencies; |
| • |
| traders in securities that elect the mark-to-market method of tax accounting for their securities; |
| • |
| holders that are subject to the alternative minimum tax provisions of the Code; |
| • |
| certain expatriates or former long-term residents of the United States; |
| • |
| U.S. Holders that have a functional currency other than the U.S. dollar; |
| • |
| personal holding companies; |
| • |
| regulated investment companies; |
| • |
| real estate investment trusts; and |
| • |
| holders that hold outstanding notes or exchange notes as part of a hedge, conversion or constructive sale transaction, straddle, wash sale or other risk reduction transaction. |
If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) is a beneficial owner of outstanding notes or exchange notes, the tax treatment of a partner will generally depend upon the status of the partner, the activities of the partnership and certain determinations made at the partner level. Partners of partnerships that are beneficial owners of outstanding notes or exchange notes should consult their tax advisors.
This discussion does not address U.S. federal taxes other than income and estate tax or the tax considerations arising under the laws of any foreign, state or local jurisdiction. No ruling has been or will be obtained from the IRS regarding any of the U.S. federal income tax consequences described below. As a result, no assurance can be given that the IRS will not assert, or that a court will not sustain, a position contrary to the conclusions set forth below.
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THIS SUMMARY IS NOT A SUBSTITUTE FOR AN INDIVIDUAL ANALYSIS OF THE TAX CONSEQUENCES RELATING TO THE EXCHANGE OF OUTSTANDING NOTES FOR EXCHANGE NOTES OR THE OWNERSHIP OR DISPOSITION OF THE EXCHANGE NOTES. WE URGE YOU TO CONSULT A TAX ADVISOR REGARDING THE PARTICULAR FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES RELATING TO THE EXCHANGE OF OUTSTANDING NOTES FOR EXCHANGE NOTES OR THE OWNERSHIP OR DISPOSITION OF THE EXCHANGE NOTES IN LIGHT OF YOUR OWN SITUATION.
Exchange Offer
We believe that the exchange of outstanding notes for exchange notes pursuant to the exchange offer will not constitute a taxable event for U.S. federal income tax purposes. As a result, (1) a holder will not recognize a taxable gain or loss as a result of exchanging such holder’s outstanding notes for exchange notes; (2) the holding period of the exchange notes will include the holding period of the outstanding notes exchanged therefor; and (3) the adjusted tax basis of the exchange notes will be the same as the adjusted tax basis of the outstanding notes exchanged therefor immediately before such exchange.
U.S. Holders
The following discussion applies only to U.S. Holders of the exchange notes. As used in this discussion, a “U.S. Holder” is a beneficial owner of an exchange note that, for U.S. federal income tax purposes, is:
| • |
| an individual U.S. citizen or resident alien; |
| • |
| a corporation or other entity created or organized under U.S. law (federal or state, including the District of Columbia) and treated as a corporation for U.S. federal income tax purposes; |
| • |
| an estate the income of which is subject to U.S. federal income taxation regardless of its source; or |
| • |
| a trust if (1) a U.S. court can exercise primary supervision over the trust’s administration and one or more U.S. persons have the authority to control all substantial decisions of the trust or (2) the trust has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person. |
Payments of Interest
A U.S. Holder will be required to include the interest paid on the exchange notes as ordinary income at the time it accrues or is received in accordance with the holder’s regular method of accounting for U.S. federal income tax purposes.
Certain Contingent Payments
In certain circumstances (see “Description of the Exchange Notes — Repurchase at the Option of Holders — Change of Control”), we may be obligated to pay amounts on the exchange notes that are in excess of stated interest and principal. We intend to take the position that the possibility that holders of the exchange notes will be paid such amounts is a remote and incidental contingency as of the issue date of the exchange notes within the meaning of the applicable Treasury Regulations. Accordingly, any such additional amount should be taxable to U.S. Holders as capital gain only at the time it accrues or is received in accordance with such holder’s regular method of accounting for U.S. federal income tax purposes. Our determination that the payment of additional amounts is a remote and incidental contingency is binding upon all holders of the exchange notes, unless a holder properly discloses to the IRS that it is taking a contrary position.
Sale, Exchange, Redemption, Retirement or Other Taxable Disposition of the Exchange Notes
Generally, the sale, exchange, redemption, retirement or other taxable disposition of an exchange note will result in taxable gain or loss to a U.S. Holder equal to the difference between (1) the amount of cash plus the fair market value of any other property received by the holder in the sale, exchange, redemption, retirement or other taxable disposition (excluding amounts attributable to accrued and unpaid interest, which will be taxed as described under “— Payments of Interest” above) and (2) the holder’s adjusted tax basis in the exchange note. A U.S. Holder’s adjusted tax basis in an exchange note will generally equal the holder’s original purchase price for the outstanding note that is exchanged therefor (minus pre-issuance accrued interest, if any).
Gain or loss recognized on the sale, exchange, redemption, retirement or other taxable disposition of an exchange note will generally be capital gain or loss and will be long-term capital gain or loss if the exchange note is held for more than one year. A reduced tax rate on capital gain generally will apply to long term capital gain of a noncorporate U.S. Holder. There are limitations on the deductibility of capital losses.
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Information Reporting and Backup Withholding
Generally, interest on the exchange notes paid to a U.S. Holder is subject to information reporting with the IRS and may be subject to backup withholding (currently at a 28% rate) unless such holder (1) is a corporation or other exempt recipient and, when required, demonstrates this fact or (2) provides a taxpayer identification number and satisfies certain certification requirements. Information reporting requirements and backup withholding may also apply to the cash proceeds of a sale or other disposition of the exchange notes.
In addition to being subject to backup withholding, if a U.S. Holder does not provide us (or our paying agent) with the holder’s correct taxpayer identification number or other required information, such holder may be subject to penalties imposed by the IRS. Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against the holder’s U.S. federal income tax liability, provided that the holder furnishes certain required information to the IRS.
Medicare Tax.
Certain U.S. Holders that are individuals, estates or trusts will be subject to a 3.8% unearned income Medicare contribution tax on all or a portion of their “net investment income,” which may include all or a portion of their interest and net gains from the disposition of exchange notes. If you are a U.S. Holder that is an individual, estate or trust, you should consult your tax advisor regarding the applicability of this tax to your income and gains in respect of your investment in the exchange notes.
Non-U.S. Holders
The following discussion applies only to Non-U.S. Holders of the exchange notes. As used in this discussion, a “Non-U.S. Holder” is a beneficial owner of an exchange note that is not a U.S. Holder.
Payments of Interest
Subject to the discussion under “— Information Reporting and Backup Withholding,” below, if the portfolio interest exemption applies to a Non-U.S. Holder, payments of interest on the exchange notes will not be subject to U.S. federal income or withholding tax. The portfolio interest exemption will apply to a Non-U.S. Holder if (1) the interest is not effectively connected with such holder’s conduct of a trade or business in the United States and (2) such holder satisfies each of the following requirements:
| • |
| such holder does not own, actually or constructively, 10% or more of the total combined voting power of all classes of our stock entitled to vote; |
| • |
| such holder is not a “controlled foreign corporation” with respect to which we are a “related person,” each within the meaning of the Code; and |
| • |
| such holder certifies that it is not a U.S. person by providing a properly completed IRS Form W-8BEN or appropriate substitute form to (1) us (or our paying agent) or (2) a securities clearing organization, bank or other financial institution that (i) holds customers’ securities in the ordinary course of its trade or business, (ii) holds the Non-U.S. Holder’s exchange notes on such holder’s behalf, (iii) certifies to us (or our paying agent) under penalties of perjury that it has received from such holder a signed, written statement and (iv) provides us (or our paying agent) with a copy of this statement. |
If the portfolio interest exemption does not apply to a Non-U.S. Holder, then the gross amount of interest that such holder receives on an exchange note will be subject to U.S. withholding tax at a rate of 30% unless (1) the Non-U.S. Holder is eligible for a reduced withholding rate or exemption under an applicable income tax treaty, in which case such holder must provide a properly completed IRS Form W-8BEN or appropriate substitute form, or (2) the interest is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States (and, if a treaty applies, is attributable to a permanent establishment or fixed base maintained by such holder in the United States), in which case such holder must provide a properly completed IRS Form W-8ECI or appropriate substitute form.
Any interest that is effectively connected with a Non-U.S. Holder’s conduct of a trade or business in the United States generally will be subject to U.S. federal income tax at rates generally applicable to U.S. persons. In the case of a Non-U.S. Holder that is a foreign corporation, such interest may also be subject to the 30% branch profits tax.
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Sale, Exchange, Redemption, Retirement or Other Taxable Disposition of Exchange Notes
A Non-U.S. Holder generally will not be subject to U.S. federal income or withholding tax on gain realized on the sale, exchange, redemption, retirement or other taxable disposition of an exchange note unless:
| • |
| the gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States (and, if a treaty applies, is attributable to a permanent establishment or fixed base maintained by such holder in the United States); |
| • |
| the Non-U.S. Holder is an individual present in the United States for 183 days or more in the year of such sale, exchange, redemption or other taxable disposition and certain other conditions are met; or |
| • |
| the Non-U.S. Holder does not qualify for an exemption from backup withholding, as discussed under “— Information Reporting and Backup Withholding,” below. |
However, in certain instances a Non-U.S. Holder may be required to establish an exemption from U.S. federal income and withholding tax with respect to amounts attributable to accrued and unpaid interest on the exchange notes. See “— Payments of Interest,” above.
Certain U.S. Federal Estate Tax Considerations
Exchange notes beneficially owned by an individual who is a nonresident not a citizen of the United States (as specifically defined for U.S. federal estate tax purposes) at the time of such individual’s death will generally not be included in the decedent’s gross estate for U.S. federal estate tax purposes if any payment of interest on the exchange notes to the holder would be eligible for the portfolio interest exemption from the 30% U.S. federal withholding tax described in the first paragraph of “— Payments of Interest” above (without regard to the certification requirement).
Information Reporting and Backup Withholding
Generally, we must report to the IRS and to the Non-U.S. Holder the amount of interest paid to such holder and the amount of tax, if any, withheld with respect to those payments. Copies of the information returns reporting such interest payments and any withholding may also be made available to the tax authorities in the country in which the Non-U.S. Holder resides under the provisions of an applicable income tax treaty.
In general, a Non-U.S. Holder will not be subject to backup withholding with respect to payments of interest that we make to the holder provided that we do not have actual knowledge or reason to know that the holder is a U.S. person, as defined under the Code, and we have received from the Non-U.S. Holder the statement described above in the last bullet point under “— Payments of Interest.”
In addition, no information reporting or backup withholding will be required regarding the proceeds of the sale of an exchange note made within the United States or conducted through certain U.S.-related financial intermediaries, if the payor receives the statement described above in the last bullet point under “— Payments of Interest” and does not have actual knowledge or reason to know that the holder is a U.S. person, as defined under the Code, or the holder otherwise establishes an exemption.
Any amounts withheld under the backup withholding rules will be allowed as a refund or a credit against the Non-U.S. Holder’s U.S. federal income tax liability, provided that the required information is timely furnished to the IRS.
PLAN OF DISTRIBUTION
Based on interpretations by the staff of the SEC in no-action letters issued to third parties, we believe that you may transfer exchange notes issued under the exchange offer in exchange for the outstanding notes if:
| • |
| you acquire the exchange notes in the ordinary course of your business; and |
| • |
| you are not engaged in, and do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of such exchange notes. |
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You may not participate in the exchange offer if you are:
| • |
| an “affiliate” of us or any of our subsidiary guarantors within the meaning of Rule 405 under the Securities Act, unless you comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable; or |
| • |
| a broker-dealer that acquired outstanding notes directly from us. |
Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver this prospectus in connection with any resale of such exchange notes. To date, the staff of the SEC has taken the position that broker-dealers may fulfill their prospectus delivery requirements with respect to transactions involving an exchange of securities such as this exchange offer, other than a resale of an unsold allotment from the original sale of the outstanding notes, with this prospectus. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for outstanding notes where such outstanding notes were acquired as a result of market-making activities or other trading activities. We have agreed that, generally for a period of 180 days after the effectiveness of the registration statement for the exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until , 2014, all dealers effecting transactions in exchange notes may be required to deliver this prospectus.
Any broker-dealer or holder using the exchange offer to participate in a distribution of the securities to be acquired in the exchange offer (1) could not, under SEC staff policy, rely on the position of the SEC staff enunciated in Morgan Stanley and Co., Inc. (available June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1988), as interpreted in the SEC staff’s letter to Shearman & Sterling dated July 2, 1993, and similar no-action letters, and (2) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction and that such a secondary resale transaction should be covered by an effective registration statement containing the selling security holder information required by Item 507 or 508, as applicable, of Regulation S-K.
If you wish to receive exchange notes for your outstanding notes in the exchange offer, you will be required to make representations to us as described in “Exchange Offer — Procedures for Tendering — Your Representations to Us” in this prospectus. As indicated in the letter of transmittal, you will be deemed to have made these representations by tendering your outstanding notes in the exchange offer. In addition, if you are a broker-dealer who receives exchange notes for your own account in exchange for outstanding notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge, in the same manner, that you will deliver this prospectus in connection with any resale by you of such exchange notes.
We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions:
•
in the over-the-counter market;
•
in negotiated transactions;
•
through the writing of options on the exchange notes; or
•
a combination of such methods of resale;
at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices.
Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on such resale of exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. Each letter of transmittal states that by acknowledging that it will deliver and by delivering this prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.
141
For a period of 180 days after the effectiveness of the registration statement for the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents. We have agreed to pay all reasonable expenses incident to the exchange offer (including the expenses of one counsel for the holders of the outstanding notes) other than commissions or concessions of any broker-dealers and will indemnify the holders of the outstanding notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.
LEGAL MATTERS
Adams and Reese LLP has issued an opinion about the legality of the exchange notes.
EXPERTS
The consolidated financial statements of the Company as of December 31, 2012 and 2011 and for the years then ended have been incorporated herein by reference in reliance upon the reports of MaloneBailey LLP, independent registered public accounting firm, incorporated herein by reference, and upon the authority of said firm as experts in accounting and auditing.
Information with respect to our oil and gas reserves, as of December 31, 2012, included in this prospectus was derived from a reserve report dated March 7, 2013, prepared by Collarini Associates, independent consulting petroleum engineers, upon the authority of such firm as experts with respect to such matters covered in such report and in giving such reports.
Information with respect to our oil and gas reserves associated with Gulf of Mexico properties, as of December 31, 2013, included in this prospectus was derived from a reserve report dated December 11, 2013, prepared by DeGolyer and MacNaughton, independent consulting petroleum engineers, upon the authority of such firm as experts with respect to such matters covered in such report and in giving such reports.
142
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the U.S. Securities and Exchange Commission (the “SEC”), a registration statement on Form S-4 under the Securities Act, relating to the exchange offer. We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any documents we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the Public Reference Room. Our SEC filings are also available to the public at the SEC’s Internet site at http://www.sec.gov and our website at http://www.saratogaresources.net. Information on our website or any other website is not incorporated by reference in this prospectus and does not constitute part of this prospectus.
This prospectus is part of the registration statement and, as permitted by SEC rules, does not contain all of the information included in the registration statement.
We will provide a copy of any and all documents that we file with the SEC, including the registration statement and exhibits to any filings made with the SEC, to any person, including a beneficial owner, to whom an prospectus is delivered, without charge, upon written or oral request. You may obtain a copy of these documents by writing or telephoning:
Saratoga Resources, Inc.
Attention: Investor Relations
3 Riverway, Suite 1810
Houston, Texas 77056
(713) 458-1560
143
SARATOGA RESOURCES, INC.
INDEX TO FINANCIAL STATEMENTS
Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012 (Unaudited) | F-1 |
|
|
Consolidated Statements of Operations and Other Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2013 and 2012 (Unaudited) | F-2 |
|
|
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012 (Unaudited) | F-3 |
|
|
Notes to the Unaudited Consolidated Financial Statements | F-4 |
|
|
Reports of Independent Registered Public Accounting Firm | F-12 |
|
|
Consolidated Balance Sheets as of December 31, 2012 and 2011 | F-13 |
|
|
Consolidated Statements of Operations and Other Comprehensive Income (Loss) for the years ended December 31, 2012, 2011 and 2010 | F-14 |
|
|
Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2012, 2011 and 2010 | F-15 |
|
|
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010 | F-16 |
|
|
Notes to the Consolidated Financial Statements | F-17 |
144
The accompanying notes are an integral part of these unaudited consolidated financial statements
F-1
SARATOGA RESOURCES, INC. | |||||||||||
CONSOLIDATED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE INCOME (LOSS) | |||||||||||
(Unaudited) | |||||||||||
| |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended September 30, |
| For the Nine Months Ended September 30, | ||||||||
| 2013 |
| 2012 |
| 2013 |
| 2012 | ||||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues | $ | 17,195,776 |
| $ | 16,454,125 |
| $ | 54,185,434 |
| $ | 59,588,443 |
Oil and gas hedging |
| (717,378) |
|
| (6,490) |
|
| (226,541) |
|
| (6,490) |
Other revenues |
| 3,466 |
|
| 269,810 |
|
| 249,815 |
|
| 1,467,403 |
Total revenues |
| 16,481,864 |
|
| 16,717,445 |
|
| 54,208,708 |
|
| 61,049,356 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expense: |
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
| 5,490,268 |
|
| 4,622,010 |
|
| 15,293,422 |
|
| 13,860,709 |
Workover expense |
| 848,094 |
|
| 306,745 |
|
| 2,277,226 |
|
| 3,846,046 |
Exploration expense |
| 462,994 |
|
| 213,733 |
|
| 746,965 |
|
| 369,419 |
Loss on plugging and abandonment |
| 727,039 |
|
| - |
|
| 727,039 |
|
| 2,468,969 |
Dry hole costs |
| - |
|
| - |
|
| - |
|
| 93,353 |
Depreciation, depletion and amortization |
| 4,919,418 |
|
| 3,658,002 |
|
| 15,790,454 |
|
| 14,170,532 |
Impairment expense |
| 2,179,075 |
|
| 44,276 |
|
| 2,179,075 |
|
| 44,276 |
Accretion expense |
| 638,097 |
|
| 555,504 |
|
| 1,914,291 |
|
| 1,666,512 |
General and administrative |
| 2,365,501 |
|
| 1,971,634 |
|
| 6,804,243 |
|
| 7,042,299 |
Severance taxes |
| 1,900,292 |
|
| 1,502,134 |
|
| 5,892,904 |
|
| 5,375,259 |
Total operating expenses |
| 19,530,778 |
|
| 12,874,038 |
|
| 51,625,619 |
|
| 48,937,374 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
| (3,048,914) |
|
| 3,843,407 |
|
| 2,583,089 |
|
| 12,111,982 |
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
Interest income |
| 8,548 |
|
| 11,204 |
|
| 27,008 |
|
| 20,046 |
Interest expense |
| (5,368,376) |
|
| (4,334,389) |
|
| (15,905,464) |
|
| (13,058,178) |
Total other expense |
| (5,359,828) |
|
| (4,323,185) |
|
| (15,878,456) |
|
| (13,038,132) |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss before reorganization expense and income taxes |
| (8,408,742) |
|
| (479,778) |
|
| (13,295,367) |
|
| (926,150) |
|
|
|
|
|
|
|
|
|
|
|
|
Reorganization expense |
| - |
|
| 43,287 |
|
| 2,319 |
|
| 121,528 |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss before income taxes |
| (8,408,742) |
|
| (523,065) |
|
| (13,297,686) |
|
| (1,047,678) |
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) |
| (2,683,382) |
|
| (48,062) |
|
| (4,196,914) |
|
| (213,896) |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss | $ | (5,725,360) |
| $ | (475,003) |
| $ | (9,100,772) |
| $ | (833,782) |
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) on derivative instruments |
| (666,614) |
|
| (182,569) |
|
| 192,115 |
|
| (182,569) |
Total comprehensive income (loss) | $ | (6,391,974) |
| $ | (657,572) |
| $ | (8,908,657) |
| $ | (1,016,351) |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per share: |
|
|
|
|
|
|
|
|
|
|
|
Basic | $ | (0.19) |
| $ | (0.02) |
| $ | (0.29) |
| $ | (0.03) |
Diluted | $ | (0.19) |
| $ | (0.02) |
| $ | (0.29) |
| $ | (0.03) |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
Basic |
| 30,945,242 |
|
| 30,808,775 |
|
| 30,927,802 |
|
| 28,867,424 |
Diluted |
| 30,945,242 |
|
| 30,808,775 |
|
| 30,927,802 |
|
| 28,867,424 |
The accompanying notes are an integral part of these unaudited consolidated financial statements
F-2
SARATOGA RESOURCES, INC. | |||||
CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||
(Unaudited) | |||||
| |||||
| For the Nine Months Ended | ||||
| September 30, | ||||
| 2013 |
| 2012 | ||
Cash flows from operating activities: |
|
|
|
|
|
Net loss | $ | (9,100,772) |
| $ | (833,782) |
Adjustments to reconcile net loss to net cash provided by operating activities: |
|
|
|
|
|
Depreciation, depletion and amortization |
| 15,790,454 |
|
| 14,170,532 |
Impairment expense |
| 2,179,075 |
|
| 44,276 |
Accretion expense |
| 1,914,291 |
|
| 1,666,512 |
Amortization of debt issuance costs |
| 1,006,240 |
|
| 675,649 |
Amortization of debt discount |
| 366,709 |
|
| 265,328 |
Dry hole costs |
| - |
|
| 93,353 |
Stock-based compensation |
| 769,427 |
|
| 1,040,127 |
Loss on plugging and abandonment |
| 727,039 |
|
| 2,468,969 |
Deferred tax benefit |
| (4,295,153) |
|
| (400,666) |
Unrealized gain on hedges |
| (290,668) |
|
| 6,490 |
Changes in operating assets and liabilities: |
|
|
|
|
|
Accounts receivable |
| 4,204,469 |
|
| 4,235,306 |
Prepaids and other |
| 1,124,277 |
|
| 894,459 |
Accounts payable |
| (3,619,119) |
|
| (1,806,687) |
Revenue and severance tax payable |
| (1,483,844) |
|
| (1,542,344) |
Payments to settle asset retirement obligations |
| (1,247,239) |
|
| (586,769) |
Accrued liabilities |
| (4,581,395) |
|
| (4,720,786) |
Net cash provided by operating activities |
| 3,463,791 |
|
| 15,669,967 |
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
Additions to oil and gas property |
| (23,905,494) |
|
| (46,191,709) |
Additions to other property and equipment |
| (94,250) |
|
| (55,138) |
Proceeds from cash collateral |
| - |
|
| 2,021,628 |
Other assets |
| (1,151,793) |
|
| (1,089,153) |
Net cash used in investing activities |
| (25,151,537) |
|
| (45,314,372) |
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
Proceeds from issuance of common stock |
| 23,795 |
|
| 23,153,910 |
Repayment of short-term notes payable |
| (1,050,384) |
|
| (1,096,079) |
Net cash (used in) provided by financing activities |
| (1,026,589) |
|
| 22,057,831 |
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
| (22,714,335) |
|
| (7,586,574) |
Cash and cash equivalents - beginning of period |
| 32,302,313 |
|
| 15,874,680 |
Cash and cash equivalents - end of period | $ | 9,587,978 |
| $ | 8,288,106 |
|
|
|
|
|
|
Supplemental disclosures of cash flow information: |
|
|
|
|
|
Cash paid for income taxes | $ | 98,239 |
| $ | 186,770 |
Cash paid for interest |
| 19,082,534 |
|
| 7,987,234 |
|
|
|
|
|
|
Non-cash investing and financing activities: |
|
|
|
|
|
Unrealized gain on derivative instruments | $ | 192,115 |
| $ | - |
Accounts payable for oil and gas additions |
| 4,244,015 |
|
| 6,075,835 |
Accrued liabilities for oil and gas additions |
| 435,998 |
|
| 1,708,702 |
Prepaid insurance financed with debt |
| 1,523,305 |
|
| 1,685,206 |
The accompanying notes are an integral part of these unaudited consolidated financial statements
F-3
SARATOGA RESOURCES, INC.
Notes to Consolidated Financial Statements
September 30, 2013
(Unaudited)
NOTE 1 – ORGANIZATION AND BASIS OF PRESENTATION
Organization
Saratoga Resources, Inc. (“Saratoga” or the “Company”) is an independent oil and natural gas company engaged in the acquisition, development, exploitation and production of natural gas and crude oil properties.
Financial Statements Presented
The accompanying unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q. They do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America for a complete financial presentation. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, considered necessary for a fair presentation, have been included in the accompanying unaudited financial statements. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.
The Company utilizes the successful efforts method of accounting for oil and gas producing activities.
These financial statements should be read in conjunction with the financial statements and footnotes which are included as part of the Company’s Form 10-K for the year ended December 31, 2012.
Reclassifications of Prior Period Statements
Certain reclassifications of prior period consolidated financial statement balances have been made to conform to current reporting practices.
Concentration of Credit Risk
Financial instruments that potentially subject the Company to a concentration of credit risk include cash, cash equivalents and any marketable securities. The Company had cash deposits of approximately $9.3 million in excess of FDIC insured limits at the period end. The Company has not experienced any losses on its deposits of cash and cash equivalents.
NOTE 2 – OIL AND GAS PROPERTIES
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.
During three months ended September 30, 2013, we recognized $2,179,075 in impairment expense. The impairment related to the loss of a lease in Louisiana. During the three months ended September 30, 2012 we recognized $44,276 in impairment expense. The impairment was a result of one of three producing wells in a field becoming fully depleted during the quarter.
F-4
NOTE 3 – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objective and Strategies for Using Commodity Derivative Instruments
The Company periodically enters into commodity derivative instruments, primarily fixed price swaps, to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company. The fixed price swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price. The amount payable by us, if the floating price is above the fixed price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed price with respect to each calculation period. The amount payable by the counterparty, if the floating price is below the fixed price, is the product of the notional quantity per calculation period and the excess of the fixed price over the floating price with respect to each calculation period.
While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits from future increases in commodity prices.
See Note 4 – “Fair Value Measurements” for a discussion of the methods and assumptions used to estimate the fair values of our commodity derivative instruments.
The Company utilizes hedge accounting for our commodity derivative instruments, which are designated as cash flow hedges.
Counterparty Credit Risk
Commodity derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are with two and one counterparties at September 30, 2013 and December 31, 2012, respectively. We monitor and manage our level of financial exposure with respect to the counterparties we use. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.
We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk.
As of September 30, 2013, the Company had the following hedge contracts outstanding:
|
| Beginning |
| Ending |
| Fixed |
| Total | |
Instrument |
| Date |
| Date |
| Price |
| Bbls | |
Fixed Price Swap |
| April 2013 |
| December 2013 |
| $ | 106.82 |
| 46,000 |
Fixed Price Swap |
| April 2013 |
| March 2014 |
| $ | 109.20 |
| 83,250 |
Fixed Price Swap |
| October 2013 |
| December 2013 |
| $ | 107.43 |
| 23,000 |
Fixed Price Swap |
| January 2014 |
| March 2014 |
| $ | 105.18 |
| 45,000 |
|
|
|
|
|
|
|
|
| 197,250 |
The following table presents the fair value of the Company’s commodity derivative instruments at September 30, 2013 and December 31, 2012:
|
| September 30, |
| December 31, | ||
Description |
| 2013 |
| 2012 | ||
Current Assets: |
|
|
|
|
|
|
Commodity derivatives |
| $ | 311,697 |
| $ | - |
|
| $ | 311,697 |
| $ | - |
Current liabilities: |
|
|
|
|
|
|
Commodity derivatives |
| $ | - |
| $ | 171,086 |
|
| $ | - |
| $ | 171,086 |
F-5
NOTE 4 – FAIR VALUE MEASUREMENTS
The Company has various financial instruments that are measured at fair value in the financial statements, including commodity derivatives. The Company’s financial assets and liabilities are measured using input from three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
Level 1 – Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the assets or liability and inputs that are derived principally from, or corroborated by, observable market data by correlation or other means (market corroborated inputs).
Level 3 – Unobservable inputs that reflect the Company’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, using internal and external data.
The following table presents the Company’s assets and liabilities recognized in the balance sheet and measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012:
|
| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||
September 30, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
| $ | - |
| $ | 311,697 |
| $ | - |
| $ | 311,697 |
|
| $ | - |
| $ | 311,697 |
| $ | - |
| $ | 311,697 |
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012 |
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
| $ | - |
| $ | 171,086 |
|
| - |
| $ | 171,086 |
|
| $ | - |
| $ | 171,086 |
|
| - |
| $ | 171,086 |
The Company uses various commodity derivative instruments, including fixed price swaps. We consider the fair value of our commodity derivative instruments to be level 2 on the fair value hierarchy. The fair value of commodity derivatives is determined using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data.
NOTE 5 – OTHER ASSETS
Other assets consist of the following:
| September 30, |
| December 31, | ||
| 2013 |
| 2012 | ||
Site specific trust accounts - P&A escrow | $ | 5,515,428 |
| $ | 5,279,084 |
Debt issuance cost, net |
| 4,767,394 |
|
| 5,728,755 |
Restricted cash – P&A bond |
| 9,738,367 |
|
| 8,873,497 |
Other |
| 53,758 |
|
| 48,058 |
| $ | 20,074,947 |
| $ | 19,929,394 |
Site Specific Trust Accounts – P&A Escrow
The Company maintains an escrow agreement that has been established for the purpose of assuring maintenance and administration of a performance bond which secures certain plugging and abandonment obligations assumed in the acquisition of oil and gas properties in certain fields. Changes in the escrow accounts reflect additional contributions and interest earned during 2013. See Note 9 – “Asset Retirement Obligations”.
F-6
Debt Issuance Costs, Net
The Company capitalizes certain debt issuance costs and amortizes those costs as additional interest expense over the lives of the associated debt. Net debt issuance costs at September 30, 2013 and December 31, 2012 reflect the issuance of the 2016 Notes in December 2012 and July 2011. See Note 10 – “Debt”.
Restricted Cash – P&A Bond
Restricted Cash – P&A Bond consists of cash collateral held in escrow to assure maintenance and administration of performance bonds which secures certain plugging and abandonment obligations imposed by state law. The cash collateral is reflected as a long term asset to correspond with the expected timing of the related asset retirement obligation liability. See Note 8 – “Asset Retirement Obligations”.
NOTE 6 – STOCK-BASED COMPENSATION EXPENSE
The Company periodically grants restricted stock and stock options to employees, directors and consultants. The Company is required to make estimates of the fair value of the related instruments and recognize expense over the period benefited, usually the vesting period.
Compensation Plan
In September 2011, the Company’s board of directors adopted, and in June 2012 the Company’s stockholders approved, the Saratoga Resources, Inc. 2011 Omnibus Equity Plan (the “2011 Plan”). The 2011 Plan reserves a total of 3,000,000 shares for issuance to eligible employees, officers, directors and other service providers pursuant to grants of options, restricted stock, performance stock and other equity based compensation agreements.
Stock Option Activity
In April 2013, the Company’s management approved a stock option grant to purchase an aggregate of 75,000 shares of common stock to two non-executive employees. The options are exercisable for a term of seven years at prices ranging from $2.34 to $2.42 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $178,200. The options were valued using the Black-Scholes model with the following assumptions: 240% volatility; 4.5 year estimated life; zero dividends; 0.60% to 0.62% discount rate; and, quoted stock price and exercise price of $2.34 to $2.42.
In June 2013, the Company’s board of directors approved a stock option grant to purchase an aggregate of 500,000 shares of common stock to two executive officers. The options are exercisable for a term of five years at $3.00 per share and vest 1/8 per quarter. The grant date value of the options was $505,000. The options were valued using the Black-Scholes model with the following assumptions: 83% volatility; 3.06 year estimated life; zero dividends; 0.57% discount rate; and, quoted stock price of $2.18.
In June 2013, the Company’s board of directors approved a stock option grant to purchase an aggregate of 105,000 shares of common stock to non-employee directors. The options are exercisable for a term of seven years at $2.18 per share and vest ½ on the date of grant and ½ on the first anniversary of the grant date. The grant date value of the options was $174,300. The options were valued using the Black-Scholes model with the following assumptions: 121% volatility; 3.75 year estimated life; zero dividends; 0.77% discount rate; and, quoted stock price and exercise price of $2.18.
In July 2013, the Company’s management approved a stock option grant to purchase an aggregate of 60,000 shares of common stock to a non-executive employee. The options are exercisable for a term of seven years at price of $1.53 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $90,600. The options were valued using the Black-Scholes model with the following assumptions: 231% volatility; 4.5 year estimated life; zero dividends; 1.18% discount rate; and, quoted stock price and exercise price of $1.53.
In August 2013, the Company’s management approved a stock option grant to purchase an aggregate of 90,000 shares of common stock to a non-executive employee. The options are exercisable for a term of seven years at price of $1.72 per share and vest 1/3 on each of the first three grant date anniversaries. The grant date value of the options was $150,300. The options were valued using the Black-Scholes model with the following assumptions: 204% volatility; 4.5 year estimated life; zero dividends; 1.18% discount rate; and, quoted stock price and exercise price of $1.72.
F-7
The following table summarizes information about stock option activity and related information for the nine months ended September 30, 2013:
| Number of Shares Underlying Options |
| Weighted Average Exercise Price per Share |
| Weighted Average Grant Date Fair Value per Share |
| Weighted Average Remaining Contractual Life (in Years) |
| Aggregate Intrinsic Value (1) | ||||
Outstanding at December 31, 2012 |
| 784,000 |
| $ | 3.66 |
| $ | 3.65 |
| 6.5 |
| $ | 474,240 |
Granted |
| 830,000 |
|
| 2.60 |
|
| 1.32 |
| 5.5 |
|
| 132,000 |
Exercised |
| (6,500) |
|
| 1.53 |
|
| 1.53 |
| - |
|
| - |
Forfeited |
| - |
|
| - |
|
| - |
| - |
|
| - |
Outstanding at September 30, 2013 |
| 1,607,500 |
| $ | 3.13 |
| $ | 2.46 |
| 5.6 |
| $ | 278,575 |
Exercisable at September 30, 2013 |
| 742,500 |
| $ | 3.35 |
| $ | 3.13 |
| 5.8 |
| $ | 157,075 |
(1)
The intrinsic value of an option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option. On September 30, 2013, the last reported sales price of our common stock on the NYSE MKT was $2.38 per share.
Share-Based Compensation Expense
The following table reflects share-based compensation recorded by the Company for the three and nine months ended September 30, 2013 and 2012:
| Three Months Ended September 30, |
| Nine Months Ended September 30, | ||||||||
| 2013 |
| 2012 |
| 2013 |
| 2012 | ||||
Share-based compensation expense included in reported net income | $ | 233,132 |
| $ | 204,833 |
| $ | 769,427 |
| $ | 1,040,127 |
Basic earnings per share effect of share-based compensation expense | $ | (0.01) |
| $ | (0.01) |
| $ | (0.02) |
| $ | (0.04) |
As of September 30, 2013, total unrecognized stock-based compensation expense related to non-vested stock options was $0.8 million. The unrecognized expense is expected to be recognized over a weighted average period of 0.7 years.
NOTE 7 – EQUITY
Common Stock Activity
In January 2013, the Company received gross proceeds of $9,945 for 6,500 stock options exercised at $1.53 a share.
In May 2013, the Company received gross proceeds of $5,100 for 30,000 stock warrants exercised at $0.17 a share.
In July 2013, the Company received gross proceeds of $8,750 for 5,000 stock warrants exercised at $1.75 a share.
Warrant Activity
The following table summarizes information about stock warrant activity and related information for the nine months ended September 30, 2013:
| Number of Shares Underlying Warrants |
| Weighted Average Exercise Price per Share |
| Weighted Average Grant Date Fair Value per Share |
| Weighted Average Remaining Contractual Life (in Years) |
| Aggregate Intrinsic Value (1) | ||||
Outstanding at December 31, 2012 |
| 572,628 |
| $ | 5.14 |
| $ | 3.22 |
| 0.8 |
| $ | 132,900 |
Granted |
| - |
|
| - |
|
| - |
| - |
|
| - |
Exercised |
| (35,000) |
|
| 0.40 |
|
| 0.22 |
| - |
|
| - |
Forfeited |
| (390,630) |
|
| 5.00 |
|
| 2.69 |
| - |
|
| - |
Outstanding at September 30, 2013 |
| 146,998 |
| $ | 6.64 |
| $ | 5.33 |
| 1.6 |
| $ | - |
Exercisable at September 30, 2013 |
| 146,998 |
| $ | 6.64 |
| $ | 5.33 |
| 1.6 |
| $ | - |
(1)
The intrinsic value of a warrant is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the warrant. On September 30, 2013, the last reported sales price of our common stock on the NYSE MKT was $2.38 per share.
F-8
NOTE 8 – EARNINGS (LOSS) PER SHARE
A reconciliation of the components of basic and diluted net loss per common share is presented in the tables below:
| For the Three Months Ended September 30, | ||||||||||||||
| 2013 |
| 2012 | ||||||||||||
| Income (Loss) |
| Weighted Average Common Shares Outstanding |
| Per Share |
| Income (Loss) |
| Weighted Average Common Shares Outstanding |
| Per Share | ||||
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to common stock | $ | (5,725,360) |
| 30,945,242 |
| $ | (0.19) |
| $ | (475,003) |
| 30,808,775 |
| $ | (0.03) |
Effect of Dilutive Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and other |
|
|
| - |
|
|
|
|
|
|
| - |
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to common stock, including assumed conversions | $ | (5,725,360) |
| 30,945,242 |
| $ | (0.19) |
| $ | (475,003) |
| 30,808,775 |
| $ | (0.03) |
| For the Nine Months Ended September 30, | ||||||||||||||
| 2013 |
| 2012 | ||||||||||||
| Income (Loss) |
| Weighted Average Common Shares Outstanding |
| Per Share |
| Income (Loss) |
| Weighted Average Common Shares Outstanding |
| Per Share | ||||
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to common stock | $ | (9,100,772) |
| 30,927,802 |
| $ | (0.29) |
| $ | (833,782) |
| 28,867,424 |
| $ | (0.03) |
Effect of Dilutive Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and other |
|
|
| - |
|
|
|
|
|
|
| - |
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to common stock, including assumed conversions | $ | (9,100,772) |
| 30,927,802 |
| $ | (0.29) |
| $ | (833,782) |
| 28,867,424 |
| $ | (0.03) |
NOTE 9 – ASSET RETIREMENT OBLIGATIONS
The Company accounts for plugging and abandonment costs in accordance with FASB Accounting Standards Codification 410-20, Accounting for Asset Retirement Obligations.
A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations are as follows:
Balance at December 31, 2012 | $ | 17,071,936 |
Accretion expense |
| 1,914,291 |
Additions |
| - |
Revisions |
| - |
Settlements |
| (520,199) |
Balance at September 30, 2013 | $ | 18,466,028 |
NOTE 10 – DEBT
Long-term debt consists of the following:
| September 30, |
| December 31, | ||
| 2013 |
| 2012 | ||
12.5% Senior Secured Notes due 2016 | $ | 152,500,000 |
| $ | 152,500,000 |
Less unamortized discount |
| 1,737,397 |
|
| 2,104,106 |
| $ | 150,762,603 |
| $ | 150,395,894 |
F-9
2016 Notes
In July 2011, the Company and the several wholly-owned subsidiaries of the Company (the “Guarantors”) entered into a Purchase Agreement with Imperial Capital, LLC (the “Initial Purchaser”), relating to the issuance and sale of $127.5 million in aggregate principal amount of the Company’s 12.5% Senior Secured Notes due 2016 (the “2016 Notes”). The 2016 Notes were sold at 98.221% of par. The 2016 Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act. The 2016 Notes were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act and to persons outside of the U.S. pursuant to Regulation S.
In December 2012, the Company and the Guarantors entered into another Purchase Agreement with the Initial Purchaser, relating to the issuance and sale of an additional $25 million in aggregate principal amount of the Company’s 2016 Notes. The 2016 Notes were sold at 98.58% of par. The 2016 Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act. The 2016 Notes were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act and to persons outside of the U.S. pursuant to Regulation S.
The 2016 Notes were issued pursuant to an indenture, dated July 12, 2011 (the “Base Indenture”), among the Company, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”) and as collateral agent (the “Collateral Agent”) and, with respect to the 2016 Notes issued in 2012, a First Supplemental Indenture, dated December 4, 2012 (the “Supplemental Indenture” and, together with the Base Indenture, the “Indenture”). The 2016 Notes are the senior secured obligations of the Company and are fully and unconditionally guaranteed on a senior secured basis by the Guarantors and will rank equally in right of payment with the Company’s and the Guarantors’ existing and future senior indebtedness.
The 2016 Notes mature on July 1, 2016, and interest is payable on the 2016 Notes on January 1 and July 1 of each year, commencing January 1, 2012.
The Indenture includes customary events of default and places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
The Company has the option to redeem all or a portion of the 2016 Notes at any time on or after January 1, 2014 at the redemption prices specified in the Indenture plus accrued and unpaid interest. The Company may also redeem the 2016 Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, plus accrued and unpaid interest, at any time prior to January 1, 2014. Within each twelve-month period commencing on July 12, 2012 and ending January 1, 2014, the Company may also redeem up to 10% of the aggregate principal amount of the 2016 Notes at a price equal to 106.25% of the principal amount thereof, plus accrued and unpaid interest. In addition, the Company may redeem up to 35% of the 2016 Notes prior to January 1, 2014 under certain circumstances with the net cash proceeds from certain equity offerings and at a price equal to 112.5% of the principal amount thereof, plus accrued and unpaid interest.
NOTE 11 – COMMITMENTS AND CONTINGENCIES
Contingencies
From time to time the Company may become involved in litigation in the ordinary course of business. At September 30, 2013, the Company’s management was not aware, and as of the date of this report is not aware, of any such litigation that could have a material adverse effect on its results of operations, cash flows or financial condition.
The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of September 30, 2013, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s properties.
F-10
Contractual Commitments – Employment Agreements
The Company has employment agreements with its Chairman and Chief Executive Officer, Thomas Cooke, and its President, Andrew Clifford. Each of the employment agreements has a three-year term and automatically renews for additional one-year terms thereafter unless either parties provides notice of non-renewal at least thirty days in advance of the end of the then current term.
The employment agreements reflect the following principal terms of employment of Messrs. Cooke and Clifford: (i) the annual base salary of Messrs. Cooke and Clifford is $317,200, effective July 1, 2013 and increases by 4% on July 1 of each succeeding year; (ii) the automobile allowance of Messrs. Cooke and Clifford either provides a Company vehicle or pays a monthly automobile allowance, which allowance is $950 per month; additionally, beyond repair and maintenance costs the automobile allowance covers all costs of operating a vehicle; (iii) the expense reimbursement provisions provide that the Company will pay all incremental costs associated with maintenance of home offices by Messrs. Cooke and Clifford, including costs of internet service, telephone and facsimile service and, with respect to Mr. Clifford, a home workstation; (iv) the agreements provide travel pay in the amount of $200 per day to Messrs. Cooke and Clifford for each overnight stay or out-of-town travel of twenty-four hours exclusively for business purposes; (v) Messrs. Cooke and Clifford each received options to purchase 250,000 shares of common stock exercisable at $3.00 per share for a term of five years and vesting on a quarterly basis over eight quarters; (vi) in the event of termination of employment due to death or disability, the Company will continue to pay base salary to the executive or his estate for a period of twelve months; and (vii) in the event of termination of employment by the Company without cause or by the executive for “good reason”, the Company shall pay a lump sum to the executive in an amount equal to two times the base salary and bonus paid during the twelve months immediately preceding termination and shall continue to provide health insurance for a period of twenty-four months.
NOTE 12 – SUBSEQUENT EVENTS
In October 2013, the Company received $620,500 in proceeds for the sale of crude oil call options. The options provided for a premium of $6.80 per Bbl for a total of 91,250 Bbls. The call options cover 250 Bbls per day beginning on April 1, 2014 and ending on March 31, 2015 at an option strike price of $103.30. The short crude oil call option, when combined with the Company’s long production position, represents a “covered call”, and creates a $103.30 per Bbl ceiling on the price to be received during the covered period for the related production.
F-11
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Saratoga Resources, Inc.
Houston, Texas
We have audited the consolidated balance sheets of Saratoga Resources, Inc. and its subsidiaries (collectively, the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity (deficit), and cash flows for the years ended December 31, 2012, 2011 and 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Saratoga Resources, Inc. and its subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for the years ended December 31, 2012, 2011 and 2010, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Saratoga Resources, Inc.’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated April 1, 2013 expressed an adverse opinion thereon.
www.malone-bailey.com
Houston, Texas
April 1, 2013
F-12
Saratoga Resources, Inc.
CONSOLIDATED BALANCE SHEETS
| December 31, | ||||
| 2012 |
| 2011 | ||
ASSETS |
|
|
|
|
|
Current assets: |
|
|
|
|
|
Cash and cash equivalents | $ | 32,302,313 |
| $ | 15,874,680 |
Accounts receivable |
| 12,430,158 |
|
| 10,539,757 |
Prepaid expenses and other |
| 1,268,971 |
|
| 1,189,406 |
Deferred tax asset, net |
| - |
|
| 1,400,000 |
Other current assets |
| 150,000 |
|
| 150,000 |
Total current assets |
| 46,151,442 |
|
| 29,153,843 |
|
|
|
|
|
|
Property and equipment: |
|
|
|
|
|
Oil and gas properties - proved (successful efforts method) |
| 260,916,084 |
|
| 196,101,827 |
Other |
| 795,138 |
|
| 658,113 |
|
| 261,711,222 |
|
| 196,759,940 |
Less: Accumulated depreciation, depletion and amortization |
| (81,640,272) |
|
| (53,830,820) |
Total property and equipment, net |
| 180,070,950 |
|
| 142,929,120 |
|
|
|
|
|
|
Deferred tax asset, net |
| 8,499,575 |
|
| 5,147,962 |
Other assets, net |
| 19,929,394 |
|
| 20,531,218 |
Total assets | $ | 254,651,361 |
| $ | 197,762,143 |
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
Accounts payable | $ | 7,259,244 |
| $ | 4,598,534 |
Revenue and severance tax payable |
| 6,129,867 |
|
| 5,709,773 |
Accrued liabilities |
| 10,787,044 |
|
| 8,451,655 |
Derivative liabilities – short term |
| 171,086 |
|
| - |
Short-term notes payable |
| 373,360 |
|
| 344,256 |
Asset retirement obligation – current |
| 256,200 |
|
| 1,548,945 |
Total current liabilities |
| 24,976,801 |
|
| 20,653,163 |
|
|
|
|
|
|
Long-term liabilities |
|
|
|
|
|
Asset retirement obligation |
| 16,815,736 |
|
| 9,852,920 |
Long-term debt, net of discount of $2,104,106 and $2,115,195, respectively |
| 150,395,894 |
|
| 125,384,805 |
Total long-term liabilities |
| 167,211,630 |
|
| 135,237,725 |
|
|
|
|
|
|
Commitment and contingencies (see notes) |
|
|
|
|
|
|
|
|
|
|
|
Stockholders' equity: |
|
|
|
|
|
Common stock, $0.001 par value; 100,000,000 shares authorized 30,905,101 and 26,714,815 shares issued and outstanding at December 31, 2012 and 2011, respectively |
| 30,905 |
|
| 26,714 |
Additional paid-in capital |
| 77,140,451 |
|
| 52,674,252 |
Accumulated other comprehensive loss |
| (171,086) |
|
| - |
Retained earnings |
| (14,537,340) |
|
| (10,829,711) |
|
|
|
|
|
|
Total stockholders' equity |
| 62,462,930 |
|
| 41,871,255 |
|
|
|
|
|
|
Total liabilities and stockholders' equity | $ | 254,651,361 |
| $ | 197,762,143 |
See notes to consolidated financial statements.
F-13
Saratoga Resources, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE INCOME(LOSS)
| For the Year Ended | |||||||
| December 31, | |||||||
| 2012 |
| 2011 |
| 2010 | |||
Revenues: |
|
|
|
|
|
|
|
|
Oil and gas revenues | $ | 82,528,932 |
| $ | 76,159,268 |
| $ | 52,734,207 |
Oil and gas hedging |
| 72,078 |
|
| - |
|
| - |
Other revenues |
| 1,411,465 |
|
| 4,774,882 |
|
| 2,284,008 |
|
|
|
|
|
|
|
|
|
Total revenues |
| 84,012,475 |
|
| 80,934,150 |
|
| 55,018,215 |
|
|
|
|
|
|
|
|
|
Operating Expense: |
|
|
|
|
|
|
|
|
Lease operating expense |
| 19,317,283 |
|
| 17,123,890 |
|
| 13,774,406 |
Workover expense |
| 3,828,197 |
|
| 2,666,600 |
|
| 2,154,482 |
Exploration expense |
| 547,192 |
|
| 596,065 |
|
| 1,921,943 |
Loss on plugging and abandonment |
| 2,468,969 |
|
| 393,599 |
|
| - |
Dry hole costs |
| 93,353 |
|
| 3,912,823 |
|
| - |
Depreciation, depletion and amortization |
| 27,407,700 |
|
| 15,591,048 |
|
| 16,001,826 |
Impairment expense |
| 401,752 |
|
| 641,791 |
|
| - |
Accretion expense |
| 1,510,165 |
|
| 1,672,900 |
|
| 1,668,268 |
Gain on revision of asset retirement obligations |
| (245,007) |
|
| (303,633) |
|
| - |
Gain on purchase price adjustment |
| - |
|
| (1,426,778) |
|
| - |
Loss on settlement of accounts payable |
| - |
|
| - |
|
| 990,786 |
General and administrative |
| 8,584,486 |
|
| 8,704,536 |
|
| 8,476,124 |
Severance taxes |
| 7,768,426 |
|
| 6,090,666 |
|
| 5,214,677 |
|
|
|
|
|
|
|
|
|
Total operating expenses |
| 71,682,516 |
|
| 55,663,507 |
|
| 50,202,512 |
|
|
|
|
|
|
|
|
|
Operating income |
| 12,329,959 |
|
| 25,270,643 |
|
| 4,815,703 |
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
Commodity derivative expense, net |
| - |
|
| - |
|
| 696,550 |
Interest income |
| 32,433 |
|
| 248,935 |
|
| 115,350 |
Interest expense |
| (17,651,496) |
|
| (17,947,784) |
|
| (22,584,934) |
Financing expense |
| (7,527) |
|
| (837,364) |
|
| - |
Gain on extinguishment of debt |
| - |
|
| 7,708,486 |
|
| - |
|
|
|
|
|
|
|
|
|
Total other expense |
| (17,626,590) |
|
| (10,827,727) |
|
| (21,773,034) |
|
|
|
|
|
|
|
|
|
Net income (loss) before reorganization expenses and income taxes |
| (5,296,631) |
|
| 14,442,916 |
|
| (16,957,331) |
Reorganization expenses |
| 161,416 |
|
| 436,092 |
|
| 2,198,359 |
Net income (loss) before income taxes |
| (5,458,047) |
|
| 14,006,824 |
|
| (19,155,690) |
Income tax provision (benefit) |
| (1,750,418) |
|
| (6,839,117) |
|
| 285,838 |
Net income (loss) | $ | (3,707,629) |
| $ | 20,845,941 |
| $ | (19,441,528) |
|
|
|
|
|
|
|
|
|
Other Comprehensive income(loss) |
|
|
|
|
|
|
|
|
Unrealized loss on derivative instruments |
| (171,086) |
|
| - |
|
| - |
Total comprehensive income (loss) | $ | (3,878,715) |
| $ | 20,845,941 |
| $ | (19,441,528) |
|
|
|
|
|
|
|
|
|
Net income (loss) per share: |
|
|
|
|
|
|
|
|
Basic | $ | (0.13) |
| $ | 0.95 |
| $ | (1.14) |
Diluted | $ | (0.13) |
| $ | 0.93 |
| $ | (1.14) |
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding: |
|
|
|
|
|
|
|
|
Basic |
| 29,378,542 |
|
| 21,975,480 |
|
| 16,996,166 |
Diluted |
| 29,378,542 |
|
| 22,367,696 |
|
| 16,996,166 |
See notes to consolidated financial statements.
F-14
Saratoga Resources, Inc.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
|
|
|
|
|
| Additional |
| Net |
| Other |
| Total | ||||
| Common Stock |
| Paid-in |
| Income |
| Comprehensive |
| Stockholders’ | |||||||
| Shares |
|
| Amount |
| Capital |
| (Loss) |
| (Loss) |
| Equity (Deficit) | ||||
Balance, December 31, 2009 | 16,690,292 |
| $ | 16,690 |
| $ | 19,887,814 |
| $ | (12,234,124) |
| $ | - |
| $ | 7,670,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common issued to vendors | 483,306 |
|
| 483 |
|
| 990,302 |
|
| - |
|
| - |
|
| 990,785 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common issued for services | 125,000 |
|
| 125 |
|
| 287,375 |
|
| - |
|
| - |
|
| 287,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of warrants issued in connection |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
with debt restructuring | - |
|
| - |
|
| 4,099,116 |
|
| - |
|
| - |
|
| 4,099,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of warrants issued for services | - |
|
| - |
|
| 120,000 |
|
| - |
|
| - |
|
| 120,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based employee compensation | - |
|
| - |
|
| 2,162,644 |
|
| - |
|
| - |
|
| 2,162,644 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss | - |
|
| - |
|
| - |
|
| (19,441,528) |
|
| - |
|
| (19,441,528) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010 | 17,298,598 |
|
| 17,298 |
|
| 27,547,251 |
|
| (31,675,652) |
|
| - |
|
| (4,111,103) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock options exercised | 118,354 |
|
| 118 |
|
| 43,082 |
|
| - |
|
| - |
|
| 43,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock warrants exercised | 1,043,748 |
|
| 1,044 |
|
| (1,044) |
|
| - |
|
| - |
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued in private placement | 8,254,115 |
|
| 8,254 |
|
| 34,761,844 |
|
| - |
|
| - |
|
| 34,770,098 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of warrants cancelled in debt restructuring | - |
|
| - |
|
| (10,620,000) |
|
| - |
|
| - |
|
| (10,620,000) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based employee compensation | - |
|
| - |
|
| 943,119 |
|
| - |
|
| - |
|
| 943,119 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income | - |
|
| - |
|
| - |
|
| 20,845,941 |
|
| - |
|
| 20,845,941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2011 | 26,714,815 |
|
| 26,714 |
|
| 52,674,252 |
|
| (10,829,711) |
|
| - |
|
| 41,871,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock options exercised | 208,599 |
|
| 209 |
|
| 405,047 |
|
| - |
|
| - |
|
| 405,256 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock warrants exercised | 892,327 |
|
| 892 |
|
| 4,460,743 |
|
| - |
|
| - |
|
| 4,461,635 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued in private placement | 3,089,360 |
|
| 3,090 |
|
| 18,394,490 |
|
| - |
|
| - |
|
| 18,397,580 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based employee compensation | - |
|
| - |
|
| 1,205,919 |
|
| - |
|
| - |
|
| 1,205,919 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive loss | - |
|
| - |
|
| - |
|
| - |
|
| (171,086) |
|
| (171,086) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income | - |
|
| - |
|
| - |
|
| (3,707,629) |
|
| - |
|
| (3,707,629) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2012 | 30,905,101 |
| $ | 30,905 |
| $ | 77,140,451 |
| $ | (14,537,340) |
| $ | (171,086) |
| $ | 62,462,930 |
See notes to consolidated financial statements.
F-15
Saratoga Resources, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the Year Ended December 31, | |||||||
| 2012 |
| 2011 |
| 2010 | |||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net income (loss) | $ | (3,707,629) |
| $ | 20,845,941 |
| $ | (19,441,528) |
Adjustments to reconcile net income (loss) to net cash used in operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and impairment |
| 27,809,452 |
|
| 16,232,839 |
|
| 16,001,826 |
Accretion expense |
| 1,510,165 |
|
| 1,672,900 |
|
| 1,668,268 |
Amortization of debt issuance costs and debt discount |
| 1,304,362 |
|
| 2,228,909 |
|
| 2,492,390 |
Commodity derivative (income) expense |
| - |
|
| - |
|
| (473,962) |
Dry hole costs |
| 93,353 |
|
| 3,912,823 |
|
| - |
Stock-based compensation |
| 1,205,919 |
|
| 943,119 |
|
| 2,570,144 |
Loss on settlement of accounts payable |
| - |
|
| - |
|
| 990,786 |
Loss on plugging and abandonment |
| 2,468,969 |
|
| 393,599 |
|
| - |
Gain on purchase price adjustment |
| - |
|
| (1,426,778) |
|
| - |
Gain on revision of asset retirement obligations |
| (245,007) |
|
| (303,633) |
|
| - |
Gain on extinguishment of debt |
| - |
|
| (7,708,486) |
|
| - |
Deferred tax benefit |
| (1,951,613) |
|
| (6,547,962) |
|
| - |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
| (1,890,401) |
|
| (1,499,920) |
|
| (1,660,182) |
Prepaids and other |
| (79,565) |
|
| (150,688) |
|
| 295,751 |
Accounts payable |
| 180,923 |
|
| (930,081) |
|
| (11,556,869) |
Revenue and severance tax payable |
| 420,094 |
|
| 641,443 |
|
| (841,880) |
Payments to settle asset retirement obligations |
| (3,062,625) |
|
| (1,148,655) |
|
| (153,655) |
Accrued liabilities |
| 2,002,499 |
|
| 6,689,890 |
|
| 8,742,502 |
Net cash provided (used) by operating activities |
| 26,058,896 |
|
| 33,845,260 |
|
| (1,366,409) |
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Additions to oil and gas property |
| (57,096,363) |
|
| (29,347,415) |
|
| (9,417,471) |
Additions to other property and equipment |
| (137,025) |
|
| (96,541) |
|
| (24,293) |
Other assets |
| 944,305 |
|
| (1,028,048) |
|
| (767,381) |
Net cash used by investing activities |
| (56,289,083) |
|
| (30,472,004) |
|
| (10,209,145) |
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Issuance of warrants |
| - |
|
| - |
|
| 100 |
Proceeds from issuance of common stock |
| 23,264,470 |
|
| 14,813,298 |
|
| - |
Proceeds from short-term notes payable |
| 1,685,226 |
|
| 1,649,068 |
|
| 1,260,276 |
Proceeds from long term debt |
| 24,645,000 |
|
| - |
|
|
|
Repayment of short-term notes payable |
| (1,656,122) |
|
| (1,590,110) |
|
| (1,389,234) |
Repayment of debt borrowings |
| - |
|
| (268,224) |
|
| (5,500,000) |
Repayment of debt borrowings - related party |
| - |
|
| (736,633) |
|
| - |
Debt issuance costs of long term debt |
| (1,280,754) |
|
| (5,775,959) |
|
| - |
Settlement of commodity hedges recorded in purchase accounting |
| - |
|
| - |
|
| 38,913 |
Net cash provided (used) by financing activities |
| 46,657,820 |
|
| 8,091,440 |
|
| (5,589,945) |
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
| 16,427,633 |
|
| 11,464,696 |
|
| (17,165,499) |
Cash and cash equivalents - beginning of period |
| 15,874,680 |
|
| 4,409,984 |
|
| 21,575,483 |
Cash and cash equivalents - end of period | $ | 32,302,313 |
| $ | 15,874,680 |
| $ | 4,409,984 |
|
|
|
|
|
|
|
|
|
Supplemental disclosures of cash flow information: |
|
|
|
|
|
|
|
|
Cash paid for income taxes | $ | 201,195 |
| $ | 130,000 |
|
| 902,491 |
Cash paid for interest |
| 8,011,117 |
|
| 8,210,196 |
|
| 10,537,405 |
|
|
|
|
|
|
|
|
|
Non-cash investing and financing activities: |
|
|
|
|
|
|
|
|
Unrealized loss on derivative instruments |
| (171,086) |
|
| - |
|
| - |
Accounts payable for oil and gas additions | $ | 2,479,787 |
| $ | 870,186 |
|
| 181,933 |
Accrued liabilities for oil and gas additions |
| 332,891 |
|
| 124,712 |
|
| 280,556 |
Revisions to asset retirement obligations |
| 4,572,244 |
|
| 1,542,172 |
|
| 281,389 |
Asset retirement obligations acquired |
| 181,318 |
|
| 67,728 |
|
| - |
Accrued interest converted to long-term debt |
| - |
|
| - |
|
| 30,811,843 |
Repayment of debt borrowing made directly to then existing lender by new lender and from proceeds from issuance of common stock |
|
|
|
| (145,231,776) |
|
|
|
Proceeds from issuance of long-term debt paid directly to then existing lender |
| - |
|
| 125,231,775 |
|
|
|
Proceeds from issuance of common stock paid directly to then existing lender |
| - |
|
| 20,000,000 |
|
|
|
Debt issuance costs from issuance of warrants |
| - |
|
| - |
|
| 4,099,016 |
See notes to consolidated financial statements.
F-16
Saratoga Resources, Inc.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Principles of Consolidation
Saratoga Resources, Inc. is an independent oil and natural gas company engaged in the production, development, acquisition and exploitation of natural gas and crude oil properties.
Our financial statements include the accounts of Saratoga Resources, Inc., a Texas corporation, and its subsidiaries. We proportionately consolidate our interests in oil and gas exploration and production ventures and partnerships in accordance with industry practice. All significant intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to “Saratoga”, “Company” “we,” “us” or “our” are to Saratoga Resources, Inc., and its subsidiaries.
Accounting for Reorganization
On March 31, 2009, Saratoga and its subsidiaries, all of which are 100%-owned: Harvest Oil and Gas, LLC, The Harvest Group, LLC, Lobo Operating, Inc. and Lobo Resources, Inc. (collectively the “Debtors”), filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code. The Debtors operated under Chapter 11 protection from the filing date on March 31, 2009 until the effective date of the Debtors’ plan of reorganization (the “Plan of Reorganization”) and exit from Chapter 11 on May 14, 2010. The accompanying consolidated financial statements of Saratoga have been prepared in accordance with FASB ASC 852, Reorganizations. The Company incurred expenses relating to the Plan of Reorganization of $161,416, $436,092 and $2,198,359 during the years ended December 31, 2012, 2011 and 2010, respectively.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Material estimates that are particularly susceptible to significant change in the near term include the determination of depreciation, depletion and amortization, plugging and abandonment liabilities, and the valuation of oil and gas property.
Reclassifications
Certain reclassifications have been made to prior years’ reported amounts in order to conform with the current year presentation. These reclassifications did not impact our net income, stockholders’ equity or cash flows.
Dependence on Oil and Gas Prices
As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for natural gas and oil. Historically, the energy markets have been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. Prices for natural gas have recently declined materially. Any continued and extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and gas reserves that we can economically produce.
Revenue Recognition
We recognize oil and gas revenue from interests in producing wells as the oil and gas is sold. Revenue from the purchase, transportation, and sale of natural gas is recognized upon completion of the sale and when transported volumes are delivered. We recognize revenue related to gas balancing agreements based on the sales method. Our net imbalance position at December 31, 2012 and 2011 was immaterial.
F-17
Concentration of Credit Risk
Financial instruments that potentially subject the Company to a concentration of credit risk include cash, cash equivalents and any marketable securities. The Company had cash deposits of approximately $32.1 million and $15.6 million in excess of FDIC insured limits at December 31, 2012 and 2011, respectively. The Company has not experienced any losses on its deposits of cash and cash equivalents.
Major Customers
Sales of oil and gas production to Shell Trading (US) Company and Shell Energy North America (US), L.P. (collectively “Shell”) accounted for 36%, 94% and 68% of our consolidated sales in 2012, 2011 and 2010, respectively. In addition, sales of oil and gas production to Plains Marketing and J. P. Morgan Ventures Energy Corp. accounted for 33% and 12%, respectively, of our consolidated sales in 2012. We believe that the loss of any of these purchasers would not have a material adverse effect on us because alternative purchasers are readily available.
Other Revenue
Other revenues consist principally of (i) a net profits interest attributable to operating the Breton Sound 31 field, for which we receive a percentage of profits, (ii) production handling fees from our Vermilion 16 field and (iii) during the 2011 period, refunds of severance taxes under a Louisiana incentive program for previously inactive wells and purchase price adjustments.
Cash and Cash Equivalents
For the purpose of the Statement of Cash Flows, we consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Accounts Receivable
Receivables are carried at original invoice amount. Uncollectible accounts receivable are charged directly against earnings when they are determined to be uncollectible. Use of this method does not result in a material difference from the valuation method required by generally accepted accounting principles. At December 31, 2012 and 2011, no reserve for allowance for doubtful accounts was needed.
Oil and Gas Operations
Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.
Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants and equipment. Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for the classification of reserves as proved, the associated leasehold costs are reclassified to proved properties.
Oil and gas exploration costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field, or while we seek government or co-venture approval of development plans or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves.
Oil and gas development costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.
F-18
Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Depletion expense for the years ended December 31, 2012, 2011 and 2010 was $27,309,204, $15,461,056 and $15,863,307, respectively.
Assets are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.
When circumstances indicate that an asset may be impaired, Saratoga compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on Saratoga’s estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. During the years ended December 31, 2012, 2011 and 2010, Saratoga recorded impairment expense of $401,752, $641,791 and $0, respectively.
We record the fair value of legal obligations to retire and remove long-lived assets in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related properties, plants and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plants and equipment is depreciated over the useful life of the related asset.
Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable and estimable.
See Note 7 – “Oil and Gas Assets”.
Derivative Instruments and Hedging Activities
All derivative instruments are recorded in our consolidated balance sheets as either an asset or liability and measured at fair value. Changes in the derivative instrument’s fair value are recognized currently in earnings, unless the derivative instrument has been designated as a cash flow hedge and specific cash flow hedge accounting criteria are met. Under cash flow hedge accounting, unrealized gains and losses are reflected in shareholders’ equity as accumulated other comprehensive Income(loss) (OCI) until the forecasted transaction occurs. The derivative’s gains or losses are then offset against related results on the hedged transaction in the statements of operations.
The Company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Only derivative instruments that are expected to be highly effective in offsetting anticipated gains or losses on the hedged cash flows and that are subsequently documented to have been highly effective can qualify for hedge accounting. Effectiveness must be assessed both at inception of the hedge and on an ongoing basis. Any ineffectiveness in hedging instruments whereby gains or losses do not exactly offset anticipated gains or losses of hedged cash flows is measured and recognized in earnings in the period in which it occurs. When using hedge accounting, we assess hedge effectiveness quarterly based on total changes in the derivative instrument’s fair value by performing regression analysis. A hedge is considered effective if certain statistical tests are met. We record hedge ineffectiveness in oil and gas hedging.
We designate our commodity derivative instruments as cash flow hedges. Changes in the fair value commodity derivative instruments used as cash flow hedges are reported in OCI, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recognized in earnings.
See Note 5 – “Derivative Instruments and Hedging Activities”.
F-19
Depreciation of Other Property and Equipment
Furniture, fixtures, equipment, and other assets are depreciated using the straight-line method over the estimated useful lives of the assets. The estimated lives of these assets range from three to five years.
Debt Issuance Costs and Debt Discount
Debt issuance costs incurred are capitalized and amortized, using the interest method, over the term of the related debt.
The amount of discount at which debt is has been issued is amortized into interest expense, using the interest method, over the term of the related debt.
Stock Based Compensation
In accordance with the provisions of the Stock Compensation Topic of the ASC (ASC Topic 718), Saratoga measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award.
Income Taxes
We account for income taxes under the provisions of the Income Taxes Topic of the ASC (ASC Topic 740). ASC Topic 740 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis
We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance. In addition we routinely assess uncertain tax positions, and accrue for tax positions that are not more-likely-than-not to be sustained upon examination by taxing authorities.
See Note 12 – “Income Taxes”.
Net Income Per Share
Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted net income per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities (see Note 11 – “Common Stock”).
Recently Issued Accounting Standards and Developments
In October 2012, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2012-04, “Technical Corrections and Improvements” in Accounting Standards Updated No. 2012-04. The amendments in this update cover a wide range of Topics in the Accounting Standards Codification. These amendments include technical corrections and improvements to the Accounting Standards Codification and conforming amendments related to fair value measurements. The amendments in this update will be effective for fiscal periods beginning after December 15, 2012. The adoption of ASU 2012-04 is not expected to have a material impact on our financial statements.
In February 2013, the FASB issued ASU No. 2013-02, amending Topic 220 – Comprehensive Income. ASU 2013-02 requires an entity to provide information in one location about amounts reclassified out of accumulated other comprehensive income by component and their corresponding effect on net income if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts not required to be reclassified to net income in their entirety, an entity is required to cross-reference to related footnote disclosures. The amendments in ASU 2013-02 will be required in interim reporting periods and are effective prospectively for the Company in the first quarter of 2013. The Company does not expect the adoption of this ASU to have a material impact on our financial statements.
NOTE 2. CHAPTER 11 REORGANIZATION
On March 31, 2009, Saratoga and its subsidiaries, all of which are 100%-owned: Harvest Oil and Gas, LLC, The Harvest Group, LLC, Lobo Operating, Inc. and Lobo Resources, Inc. (collectively the “Debtors”), filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code.
F-20
On May 14, 2010, the Company satisfied all of the conditions set forth in its Plan of Reorganization and the Company exited from bankruptcy.
During the years ended December 31, 2012, 2011 and 2010, the Company incurred $161,416, $436,092 and $2,198,359, respectively in reorganization costs.
NOTE 3. OTHER ASSETS
Other assets consist of the following:
| December 31, | ||||
| 2012 |
| 2011 | ||
Site specific trust accounts – P&A escrow | $ | 5,279,084 |
| $ | 4,629,816 |
Debt issuance cost, net |
| 5,728,755 |
|
| 5,386,274 |
Restricted cash – P&A bond |
| 8,873,497 |
|
| 10,485,128 |
Other |
| 48,058 |
|
| 30,000 |
| $ | 19,929,394 |
| $ | 20,531,218 |
Site Specific Trust Accounts – P&A Escrow
The Company maintains an escrow agreement that has been established for the purpose of assuring maintenance and administration of a performance bond which secures certain plugging and abandonment obligations assumed in the acquisition of oil and gas properties in certain fields. Changes in the escrow accounts reflect additional contributions during 2012. See Note 8 – “Asset Retirement Obligations”.
During the year ended December 31, 2011, it was discovered that certain Site Specific Trust Accounts which were in existence at the time of acquisition by Saratoga had not been reflected in the original purchase price accounting. Accordingly, the assets, totaling $1,426,778, were reflected in the balance sheet during the year and a corresponding gain on purchase price adjusted was recognized.
Debt Issuance Costs, Net
The Company capitalizes certain debt issuance costs and amortizes those costs as additional interest expense over the lives of the associated debt. Net debt issuance costs at December 31, 2012 and 2011 reflect the issuance of the 2016 Notes in December 2012 and July 2011. See Note 4 – “Debt”.
Restricted Cash – P&A Bond
Restricted Cash – P&A Bond consists of cash collateral held in escrow to assure maintenance and administration of performance bonds which secures certain plugging and abandonment obligations imposed by state law. In connection with the retirement of the debt to Wayzata Investment Partners (“Wayzata”) in July 2011, the Company retired the letter of credit obligation and posted cash collateral in lieu of the letter of credit to secure the performance bond. See Note 8 – “Asset Retirement Obligations”. The cash collateral is reflected as a long term asset to correspond with the expected timing of the related asset retirement obligation liability.
NOTE 4. DEBT
Long-term debt consists of the following:
| December 31, | ||||
| 2012 |
| 2011 | ||
12.5% Senior Secured Notes due 2016 | $ | 152,500,000 |
| $ | 127,500,000 |
Less unamortized discount |
| (2,104,106) |
|
| (2,115,195) |
|
| 150,395,894 |
|
| 125,384,805 |
F-21
2016 Notes
In July 2011, the Company and the several wholly-owned subsidiaries of the Company (the “Guarantors”) entered into a Purchase Agreement with Imperial Capital, LLC (the “Initial Purchaser”), relating to the issuance and sale of $127.5 million in aggregate principal amount of the Company’s 12.5% Senior Secured Notes due 2016 (the “2016 Notes”). The 2016 Notes were sold at 98.221% of par. The 2016 Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act. The 2016 Notes were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act and to persons outside of the U.S. pursuant to Regulation S.
In December 2012, the Company and the Guarantors entered into another Purchase Agreement with the Initial Purchaser, relating to the issuance and sale of an additional $25 million in aggregate principal amount of the Company’s 2016 Notes. The 2016 Notes were sold at 98.58% of par. The 2016 Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act. The 2016 Notes were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act and to persons outside of the U.S. pursuant to Regulation S.
The 2016 Notes were issued pursuant to an indenture, dated July 12, 2011 (the “Base Indenture”), among the Company, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”) and as collateral agent (the “Collateral Agent”) and, with respect to the 2016 Notes issued in 2012, a First Supplemental Indenture, dated December 4, 2012 (the “Supplemental Indenture” and, together with the Base Indenture, the “Indenture”). The 2016 Notes are the senior secured obligations of the Company and are fully and unconditionally guaranteed on a senior secured basis by the Guarantors and will rank equally in right of payment with the Company’s and the Guarantors’ existing and future senior indebtedness.
The 2016 Notes mature on July 1, 2016, and interest is payable on the 2016 Notes on January 1 and July 1 of each year, commencing January 1, 2012.
The Indenture includes customary events of default and places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
The Company has the option to redeem all or a portion of the 2016 Notes at any time on or after January 1, 2014 at the redemption prices specified in the Indenture plus accrued and unpaid interest. The Company may also redeem the 2016 Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, plus accrued and unpaid interest, at any time prior to January 1, 2014. Within each twelve-month period commencing on July 12, 2012 and ending January 1, 2014, the Company may also redeem up to 10% of the aggregate principal amount of the 2016 Notes at a price equal to 106.25% of the principal amount thereof, plus accrued and unpaid interest. In addition, the Company may redeem up to 35% of the 2016 Notes prior to January 1, 2014 under certain circumstances with the net cash proceeds from certain equity offerings and at a price equal to 112.5% of the principal amount thereof, plus accrued and unpaid interest.
Retirement of Wayzata Debt
In July 2011, the Company utilized net proceeds from the issuance of long-term debt and common stock amounting to $125.2 million and $20.0 million, respectively, and $0.3 million in cash on hand to pay off the Wayzata debt of $145.5 million (including outstanding letter of credit obligations of $10.2 million).
In conjunction with the early payoff of amounts owing to Wayzata, the Wayzata 2010 Warrants to purchase 2,000,000 shares were cancelled. As a result of retirement of the Wayzata debt and cancellation of the Warrants, the Company wrote off $2.9 million of unamortized debt discount and debt issuance costs and reduced additional paid-in capital by $10.6 million (see Note 10 – “Common Stock – Warrant Activity”) resulting in a net gain on the extinguishment of debt totaling $7.7 million.
F-22
NOTE 5. – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objective and Strategies for Using Commodity Derivative Instruments
The Company periodically enters into commodity derivative instruments, primarily fixed price swaps, to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company. The fixed price swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price. The amount payable by us, if the floating price is above the fixed price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed price with respect to each calculation period. The amount payable by the counterparty, if the floating price is below the fixed price, is the product of the notional quantity per calculation period and the excess of the fixed price over the floating price with respect to each calculation period.
While these instruments mitigate the cash flow risk of future reductions in commodity, they may also curtail benefits from future increases in commodity prices.
See Note 6 – “Fair Value Measurements” for a discussion of the methods and assumptions used to estimate the fair values of our commodity derivative instruments.
The Company utilizes hedge accounting for our commodity derivative instruments, which are designated as cash flow hedges
Counterparty Credit Risk
Commodity derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are all with a single counterparty at December 31, 2012. We monitor and manage our level of financial exposure with respect to the counterparties we use. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.
We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk.
As of December 31, 2012, the Company had the following hedge contracts outstanding:
|
| Beginning |
| Ending |
| Fixed |
| Total | |
Instrument |
| Date |
| Date |
| Price |
| Bbls | |
Fixed Price Swap |
| January 2013 |
| March 2013 |
| $ | 108.00 |
| 67,500 |
Fixed Price Swap |
| January 2013 |
| March 2013 |
|
| 106.00 |
| 22,500 |
Fixed Price Swap |
| January 2013 |
| March 2013 |
| $ | 108.50 |
| 45,000 |
|
|
|
|
|
|
|
|
| 135,000 |
The following table presents the fair value of the Company’s commodity derivative instruments at December 31, 2012 and 2011:
|
| December 31, | ||||
Description |
| 2012 |
| 2011 | ||
Current liabilities: |
|
|
|
|
|
|
Commodity derivatives |
| $ | 171,086 |
| $ | - |
|
| $ | 171,086 |
| $ | - |
F-23
The following tables present the effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income (loss) for the years ended December 31, 2012, 2011 and 2010:
|
| For the Year Ended December 31, | ||||||
Description |
| 2012 |
| 2011 |
| 2010 | ||
Realized mark-to-market gain |
| $ | - |
| $ | - |
| 696,550 |
Total gain on commodity derivative instruments |
| $ | - |
| $ | - |
| 696,550 |
|
| For the Year Ended December 31, | ||||||
Description |
| 2012 |
| 2011 |
| 2010 | ||
Unrealized mark-to-market loss recognized in other comprehensive income (loss) |
|
| (171,086) |
|
| - |
| - |
Total other comprehensive income (loss) |
| $ | (171,086) |
| $ | - |
| - |
NOTE 6. – FAIR VALUE MEASUREMENTS
The Company has various financial instruments that are measured at fair value in the financial statements, including commodity derivatives. The Company’s financial assets and liabilities are measured using input from three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
Level 1 – Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the assets or liability and inputs that are derived principally from, or corroborated by, observable market data by correlation or other means (market corroborated inputs).
Level 3 – Unobservable inputs that reflect the Company’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, using internal and external data.
The following table presents the Company’s assets and liabilities recognized in the balance sheet and measured at fair value on a recurring basis as of December 31, 2012:
|
| Beginning |
| Ending |
| Fixed |
|
| |||
Description |
| Level 1 |
| Level 2 |
| Level 3 |
| Total | |||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
| $ | - |
| $ | 171,086 |
| - |
| $ | 171,086 |
|
| $ | - |
| $ | 171,086 |
| - |
| $ | 171,086 |
The Company uses various commodity derivative instruments, including fixed price swaps. We consider the fair value of our commodity derivative instruments to be level 2 on the fair value hierarchy. The fair value of commodity derivatives is determined using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data.
F-24
NOTE 7. OIL AND GAS ASSETS
Property and equipment consisted of the following:
| December 31, | ||||
| 2012 |
| 2011 | ||
Oil and gas properties (proved): |
|
|
|
|
|
Gross oil and gas properties (proved) | $ | 260,916,084 |
| $ | 196,101,827 |
Accumulated depreciation, depletion, amortization and impairment |
| (81,056,770) |
|
| (53,345,814) |
Net oil and gas properties (proved) |
| 179,859,314 |
|
| 142,756,013 |
Other property and equipment |
| 795,138 |
|
| 658,113 |
Accumulated depreciation and amortization |
| (583,502) |
|
| (485,006) |
Net other property and equipment |
| 211,636 |
|
| 173,107 |
Net property and equipment | $ | 180,070,950 |
| $ | 142,929,120 |
At December 31, 2012, there were $1,233,800 in costs associated with wells in progress that were included in oil and gas properties, but were not yet included in the depletion calculation.
NOTE 8. ASSET RETIREMENT OBLIGATIONS
The Company accounts for plugging and abandonment costs in accordance with FASB ASC 410-20, Accounting for Asset Retirement Obligations.
The Company maintains an escrow agreement that has been established for the purpose of assuring maintenance and administration of a performance bond which secures certain plugging and abandonment obligations assumed in the acquisition of oil and gas properties in certain fields.
At December 31, 2012 and 2011, the amount of the escrow account totaled $5.3 million and $4.6 million, respectively and is shown as other assets on the Company’s balance sheet. See Note 3 – “Other Assets”.
During the years ended December 31, 2012 and 2011, downward revisions in the asset retirement obligations relating to two properties exceeded the carrying amount of the property. According, during the years ended December 31, 2012 and 2011, respectively, the excess amounts, which were $245,007 and $303,633, were recognized as gains.
During the years ended December 31, 2012 and 2011, plugging and abandonment costs related to two properties exceeded the amounts reflected in the asset retirement obligation liability. The wells plugged were the deepest and highest pressure wells in our entire inventory of wells to be plugged. In addition, several of the wells had unanticipated severe casing damage.. Accordingly, during the years ended December 31, 2012 and 2011, respectively, the excess amounts, which were $2,468,969 and $393,599, were recognized as losses.
A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations are as follows:
Balance at December 31, 2009 |
| 10,190,073 |
Accretion expense |
| 1,668,268 |
Additions |
| 281,389 |
Revisions |
| - |
Settlements |
| (153,655) |
Balance at December 31, 2010 | $ | 11,986,075 |
Accretion expense |
| 1,672,900 |
Additions |
| 67,728 |
Revisions |
| (1,542,172) |
Settlements |
| (782,666) |
Balance at December 31, 2011 | $ | 11,401,865 |
Accretion expense |
| 1,510,165 |
Additions |
| 181,318 |
Revisions |
| 4,572,244 |
Settlements |
| (593,656) |
Balance at December 31, 2012 | $ | 17,071,936 |
F-25
NOTE 9. RELATED PARTY TRANSACTIONS
The Company had $8,137,500 and $10,159,128 as of December 31, 2012 and 2011 in cash collateral held in escrow by Macquarie Bank (“Macquarie”) to assure maintenance and administration of performance bonds which secure certain plugging and abandonment obligations imposed by state law (see Note 3 – “Other Assets”). Macquarie affiliates own greater than 10% of the outstanding common stock of Saratoga.
Pursuant to our Plan of Reorganization, notes payable to the Company’s Chief Executive Officer and President, in the aggregate amount of $736,633 were repaid in November 2011 upon prior satisfaction of all claims under the Plan of Reorganization, and following approval of the bankruptcy court.
NOTE 10. COMMITMENTS AND CONTINGENCIES
Contractual Commitments
We have commitments under a non-cancellable operating lease agreement for our office in Houston, Texas.
Rent expense with respect to our lease commitments for office space for the years ended December 31, 2012, 2011 and 2010 was $242,594, $226,258 and $210,349, respectively.
We have certain plugging and abandonment, reclamation, restoration, and clean up liabilities and obligations related to our oil and gas properties. To secure these liabilities, we maintain $7,750,000 in letters of credit. The letters of credit are secured by cash collateral.
At December 31, 2012, total minimum commitments from debt, long-term non-cancelable operating leases, asset retirement obligations and other purchase obligations are as follows:
| Payments due by period | |||||||||||||
| Total |
| 2013 |
| 2014 – 2015 |
| 2016 – 2017 |
| Thereafter | |||||
Debt | $ | 219,218,750 |
| $ | 19,062,500 |
| $ | 38,125,000 |
| $ | 162,031,250 |
| $ | - |
Operating leases |
| 78,972 |
|
| 78,972 |
|
| - |
|
| - |
|
| - |
Capital leases |
| - |
|
| - |
|
| - |
|
| - |
|
| - |
Asset retirement obligations |
| 51,887,000 |
|
| 256,000 |
|
| 2,520,000 |
|
| 5,685,000 |
|
| 43,426,000 |
Total | $ | 271,184,722 |
| $ | 19,397,472 |
| $ | 40,645,000 |
| $ | 167,716,250 |
| $ | 43,426,000 |
Contingencies
From time to time the Company may become involved in litigation in the ordinary course of business. At December 31, 2012, the Company’s management was not aware, and as of the date of this report is not aware, other than as described below, of any such litigation that could have a material adverse effect on its results of operations, cash flows or financial condition.
In December 2009, the Parish of Plaquemines, State of Louisiana, filed supplemental assessments against multiple oil and gas companies, including Saratoga, for allegedly omitting or undervaluing oil producing assets on the annual self-reporting tax renditions used to calculate ad valorem taxes. In short, the difference between what was reported by the oil and gas companies and what the assessor taxed boiled down to how depreciation of the oil and gas related equipment was calculated and how certain equipment was classified. The amount alleged to be due by Saratoga for the years 2006, 2007, and 2008 is $1.3 million in Parish taxes. Also at issue are the increased assessment valuations for the years 2009, 2010, and 2011 brought by the Parish under the same theory. Saratoga is contesting the additional tax assessments in an action styled Aviva America, Inc., The Harvest Group, LLC, Harvest Oil & Gas, LLC, Saratoga Resources, Inc., Lobo Operating, Inc. and Lobo Resources, Inc. v. Robert R. Gravolet, In His Capacity as Assessor for Plaquemines Parish, Louisiana, 25th Judicial District Court for the Parish of Plaquemines, and, as to certain issues relating to such claim, a number of administrative proceedings before the Louisiana Tax Commission are also being fought. We believe the additional assessment is in error and intend to vigorously defend this action. Saratoga has paid $0.7 million of the additional assessments and has included the remaining $0.6 million of the $1.3 million total in accounts payable as of December 31, 2012 pending resolution of the dispute.
F-26
The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of December 31, 2012, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s properties.
Registration Rights Agreements
In connection with the 2011 and 2012 issuance and sale of the 2016 Notes, we and the Guarantors entered into separate registration rights agreements (the “Registration Rights Agreements”) with Imperial Capital. Pursuant to the Registration Rights Agreements, we and the Guarantors agreed to file registration statements with the Securities and Exchange Commission (the “SEC”) so that holders of the 2016 Notes could exchange the 2016 Notes for registered notes that have substantially identical terms as the 2016 Notes. In addition, we and the Guarantors agreed to exchange the guarantee related to the 2016 Notes for a registered guarantee having substantially the same terms as the original guarantee. We and the Guarantors agreed to use reasonable best efforts to cause a registration statement with respect to the exchange to be filed within 90 days after the issuance of the 2016 Notes and declared effective under the Securities Act within 180 days after the issuance of the 2016 Notes. In the event of a failure to comply with our obligations to register the 2016 Notes within the specified time periods or to continue to maintain the effectiveness of the registration (a “Registration Default”), the interest rate on the 2016 Notes will be increased by 0.25% for each 90 days that such Registration Default continues, provided that the increase in interest rate shall in no event exceed an aggregate of 1.0% and provided, further, that upon cure of any such Registration Default the interest rate on the 2016 Notes will be reduced to its original rate. A registration statement relating to the exchange of the 2016 Notes issued during 2011 was filed on September 26, 2011 and was declared effective by the SEC on October 19, 2011. Following the effectiveness of the registration statement, we completed the exchange of registered notes for the unregistered 2016 Notes issued in 2011. A registration statement relating to the exchange of the 2016 Notes issued during 2012 was filed on January 11, 2013 and was declared effective by the SEC on February 6, 2013. Following the effectiveness of the registration statement, we completed the exchange of registered notes for the unregistered 2016 Notes issued in 2012.
In connection with the July 2011 issuance and sale of shares, we entered into a registration rights agreement (the “2011 Equity Registration Rights Agreement”) with the purchasers of the shares. Pursuant to the 2011 Equity Registration Rights Agreement, the holders of a majority of the shares will have a demand registration right pursuant to which we may be required to file with the SEC one or more registration statements covering the resale of the shares. Additionally, the 2011 Equity Registration Rights Agreement provides “piggyback” registration rights to the holders of the shares pursuant to which the holders are entitled to notice of the filing of certain registration statements and inclusion of some or all of the shares in any such registration statements.
In connection with the 2012 issuance and sale of shares, we entered into a registration rights agreement (the “2012 Equity Registration Rights Agreement”) with the purchasers of the shares. Pursuant to the 2012 Equity Registration Rights Agreement, we undertook to file a registration statement covering the shares not later than thirty days after the closing date of the offering. In the event that we failed to file the required registration statement within said thirty day period, failed to cause the registration statement to become effective within ninety days (120 days if the registration statement was subject to review by the SEC), failed to cause the shares to be listed for quotation on an approved market or otherwise fails to either maintain the continuing effectiveness of the registration statement or to make such filings with the SEC so as to permit resales under Rule 144, we agreed to pay as partial liquidated damages one percent of the aggregate purchase price of the shares for each thirty days in which such condition continues.
On June 20, 2012, we filed a registration statement covering the resale of, among other shares, the shares covered by the 2011 Equity Registration Rights Agreement and the 2012 Equity Registration Rights Agreement. That registration statement was declared effective by the SEC on July 5, 2012.
F-27
NOTE 11. COMMON STOCK
Net Income per Common Share
A reconciliation of the components of basic and diluted net income per common share is presented in the tables below:
| For the Year Ended December 31, | |||||||
| 2012 |
| 2011 |
| 2010 | |||
|
|
|
|
|
|
|
|
|
Income (loss) attributable to common stock | $ | (3,707,629) |
| $ | 20,845,941 |
| $ | (19,441,528) |
|
|
|
|
|
|
|
|
|
Weighted average number of shares outstanding, basic |
| 29,378,542 |
|
| 21,975,480 |
|
| 16,996,166 |
Incremental shares from assumed conversion of dilutive stock options and warrants |
| - |
|
| 392,216 |
|
| - |
Weighted average number of shares outstanding, diluted: |
| 29,378,542 |
|
| 22,367,696 |
|
| 16,996,166 |
|
|
|
|
|
|
|
|
|
Net Income (loss) per share, basic |
| (0.13) |
|
| 0.95 |
|
| (1.14) |
Net Income (loss) per share, diluted |
| (0.13) |
|
| 0.93 |
|
| (1.14) |
|
|
|
|
|
|
|
|
|
Number of antidilutive stock options and warrants excluded from calculation above |
| 416,188 |
|
| - |
|
| 4,198,016 |
Common Stock Activity
Pursuant to the terms of the Company’s plan of reorganization, in May 2010, the Company issued an aggregate of 483,306 shares of common stock pro rata among oil lien claim creditors, other secured creditors and unsecured creditors. The Company recorded a loss on settlement of accounts payable in the income statement for $990,785 for the fair value of the common stock.
During the year ended December 31, 2011, the Company issued an aggregate of 118,354 shares of common stock upon the exercise of outstanding stock options by former employees. Of the shares issued, 45,000 shares were issued for gross proceeds of $43,200, or $0.96 a share, and 73,354 shares were issued pursuant to “cashless” exercise provisions wherein the intrinsic value of the stock options were delivered to the Company in lieu of cash payment of the exercise price of 183,333 stock options, with a weighted average exercise price $2.77 per share. See “-Stock Option Activity” below.
During the year ended December 31, 2011, the Company issued an aggregate of 1,043,748 shares of common stock upon the exercise of outstanding warrants. All of the shares were issued pursuant to “cashless” exercise provisions wherein the intrinsic value of the warrants were delivered to the Company in lieu of cash payment of the exercise price of 1,055,516 warrants, with a weighted average exercise price $0.06 per share. See “-Warrant Activity” below.
In April 2011, the Company sold to U.S. and non-U.S. accredited investors, in a private placement, an aggregate of 2,481,316 shares of common stock and warrants to purchase 1,240,658 shares of common stock. The shares and warrants were offered in units of two shares and one warrant at $6.00 per unit for aggregate gross proceeds of $7,443,948. Pursuant to the offering, the Company issued 84,600 shares of common stock to a placement agent with respect to units sold to non-U.S. investors.
In July 2011, the Company sold to U.S. and non-U.S. accredited and institutional investors, in a private placement, an aggregate of 5,650,000 shares of common stock at a price of $5.00 per share. Net proceeds from the sale of shares were approximately $27.3 million, of which $20.0 million was deposited directly into a third party escrow account to be applied to the retirement of indebtedness to Wayzata. Pursuant to the offering, the Company issued 38,200 shares of common stock to a placement agent with respect to shares sold to non-U.S. investors.
During the year ended December 31, 2012, the Company issued an aggregate of 208,599 shares of common stock upon the exercise of outstanding stock options by individuals, including two non-executive employees and a non-employee director. Of the shares issued, 163,500 shares were issued for gross proceeds of $405,256, or $2.48 a share, and 45,099 shares were issued pursuant to “cashless” exercise provisions wherein the intrinsic value of the stock options were delivered to the Company in lieu of cash payment of the exercise price of 70,000 stock options, with a weighted average exercise price $2.38 per share. See “-Stock Option Activity” below.
During the year ended December 31, 2012, the Company issued an aggregate of 892,327 shares of common stock upon the exercise of outstanding warrants for which the Company received $4,461,635 of proceeds, or $5.00 per share. In conjunction with the exercise of 213,996 of those warrants, the Company granted three year warrants to purchase an aggregate of 106,997 shares of common stock at $8.00 per share. See “-Warrant Activity” below.
F-28
On May 24, 2012, the Company sold, in a private placement, an aggregate of 3,089,360 shares of common stock to certain institutional and accredited investors at a price of $6.25 per share, for net proceeds of approximately $18.4 million.
Stock-Based Compensation
The Company periodically grants restricted stock and stock options to employees, directors and consultants. The Company is required to make estimates of the fair value of the related instruments when granted and recognize expense over the period benefited, usually the vesting period.
In September 2011, the Company’s board of directors adopted, and in June 2012 the Company’s stockholders approved, the Saratoga Resources, Inc. 2011 Omnibus Equity Plan (the “2011 Plan”). The 2011 Plan reserves a total of 3,000,000 shares for issuance to eligible employees, officers, directors and other service providers pursuant to grants of options, restricted stock, performance stock and other equity based compensation agreements.
In conjunction with the adoption of the 2011 Plan, the Company’s board of directors approved the termination of the Saratoga Resources, Inc. 2008 Long-term Incentive Plan (the “2008 Plan”) and the Saratoga Resources, Inc. 2006 Employee and Consultant Stock Plan (the “2006 Plan”). As of December 31, 2012, no awards were outstanding under the 2008 Plan or the 2006 Plan.
Stock Option Activity
In April 2010, the Company’s board of directors approved stock option grants to purchase an aggregate of 845,000 shares of common stock to the Company’s directors and to various key employees, including an aggregate of 50,000 stock options granted to directors and 150,000 stock options granted to an officer of the Company. 330,000 of the options granted in April 2010 were forfeited during 2010. The grant date value of the aggregate 845,000 options was $2,535,000, which includes the grant date value of the 330,000 options forfeited of $990,000. The options are exercisable at $3.00 per share for a term of ten years. The options are subject to different vesting periods. The options were valued using the Black-Sholes model with the following assumptions: $3.00 quoted stock price; $3.00 exercise price; 352% volatility; 5 to 6 year estimated life; zero dividends; 2.61% discount rate.
In July 2010, the Company granted stock options to purchase 115,000 shares of common stock to employees, including 40,000 options granted to an officer. The options are exercisable at $1.53 per share for a term of ten years and vest ratably over three years. The grant date value of the options was $175,950. The options were valued using the Black-Scholes model with the following assumptions: $1.53 quoted stock price; $1.53 exercise price; 345% volatility; 5.8 year estimated life; zero dividends; and 2.12% discount rate.
In July 2010, the Company granted stock options to purchase 120,000 shares of common stock to employees, including 100,000 options granted to an officer. The options are exercisable at $1.71 per share for a term of ten years and vest ratably over three years. The grant date value of the options was $205,200, which includes the grand date value of 20,000 options forfeited of $34,200. The options were valued using the Black-Scholes model with the following assumptions: $1.71 quoted stock price; $1.71 exercise price; 344% volatility; 6 year estimated life; zero dividends; and 2.1% discount rate.
In July 2010, the Company granted stock options to purchase 202,500 shares of common stock to consultants. The options are exercisable at $1.71 per share for a term of five years. 2,500 of the options were granted to a consultant for investor relations and vested on the date of grant. 200,000 of the stock options were granted to a consultant for business development services of which 10,000 vested on grant date. The remaining 190,000 options vest as follows: (i) 2,000 options vest each month from August 2010 to December 2010; (ii) 80,000 options vest based on satisfaction of certain performance criteria, and (iii) 25,000 options vest on each of June 30, 2011, December 31, 2011, December 31, 2012 and December 31, 2013 provided that the consultant continues to provide services to the Company as of those dates. The grant date value of the options was $61,070. The options were valued using the Black-Scholes model with the following assumptions: $1.71 quoted stock price; $1.71 exercise price; 344% volatility; 2 to 3 year estimated life; zero dividends; and 0.98% discount rate.
In August 2010, the Company granted stock options to purchase 10,000 shares of common stock to a consultant. The options are exercisable at $1.39 per share for a term of five years and vest in full on February 28, 2011. The grant date value of the options was $13,800. The options were valued using the Black-Scholes model with the following assumptions: $1.39 quoted stock price; $1.39 exercise price; 340% volatility; 2.5 year estimated life; zero dividends; and 0.98% discount rate.
F-29
In March 2011, the Company’s board of directors approved stock option grants to purchase an aggregate of 105,000 shares of common stock to the Company’s non-employee directors, including options granted to a newly appointed director. 70,000 of the options are exercisable at $3.05 per share and 35,000 of the options are exercisable at $2.80 per share. The options vested 50% on the respective grant dates and vest as to the remaining 50% one year from the grant date. The options are exercisable for a term of seven years. The grant date value of the aggregate 105,000 options was $0.3 million. The options were valued using the Black-Scholes model with the following assumptions: 346% - 347% volatility; 3.75 year estimated life; zero dividends; 1.394% discount rate as to 35,000 options and 1.64% discount rate as to 70,000 options; quoted stock price and exercise price of $2.80 per share as to 35,000 options and $3.05 per shares as to 70,000 options.
In April 2011, the Company’s board of directors approved a stock option grant to purchase an aggregate of 30,000 shares of common stock to a non-executive employee. The options are exercisable for a term of ten years at $2.75 per share and vest 1/3 on each of the first three anniversaries of the grant date. The grant date value of the options was $82,500. The options were valued using the Black-Scholes model with the following assumptions: 320% volatility; 6.0 year estimated life; zero dividends; 2.47% discount rate; and, quoted stock price and exercise price of $2.75.
In September 2011, the Company’s board of directors approved a stock option grant to purchase an aggregate of 50,000 shares of common stock to a newly hired non-executive employee. The options are exercisable for a term of seven years at $5.63 per share and vest as to 16,000 shares on the first anniversary of the grant date and as to 17,000 shares on each of the second and third anniversaries of the grant date. The grant date value of the options was $281,500. The options were valued using the Black-Scholes model with the following assumptions: 318% volatility; 6.0 year estimated life; zero dividends; 1.19% discount rate; and, quoted stock price and exercise price of $5.63.
In October 2011, the Company’s board of directors approved a stock option grant to purchase an aggregate of 30,000 shares of common stock to a newly hired non-executive employee. The options are exercisable for a term of seven years at $5.11 per share and vest as to 10,000 shares on each of the first, second and third anniversaries of the grant date. The grant date value of the options was $153,300. The options were valued using the Black-Scholes model with the following assumptions: 309% volatility; 4.5 year estimated life; zero dividends; 0.96% discount rate; and, quoted stock price and exercise price of $5.11.
In October 2011, the Company’s board of directors approved a stock option grant to purchase an aggregate of 150,000 shares of common stock to a newly hired executive employee. The options are exercisable for a term of seven years at $4.59 per share and vest as to 50,000 shares on each of the first, second and third anniversaries of the grant date. The grant date value of the options was $687,750. The options were valued using the Black-Scholes model with the following assumptions: 307% volatility; 4.5 year estimated life; zero dividends; 0.99% discount rate; and, quoted stock price and exercise price of $4.59.
In November 2011, the Company’s board of directors approved a stock option grant to purchase an aggregate of 30,000 shares of common stock to a newly hired executive employee. The options are exercisable for a term of seven years at $4.62 per share and vest as to 10,000 shares on each of the first, second and third anniversaries of the grant date. The grant date value of the options was $138,600. The options were valued using the Black-Scholes model with the following assumptions: 305% volatility; 4.5 year estimated life; zero dividends; 0.91% discount rate; and, quoted stock price and exercise price of $4.62.
In December 2011, a former employee exercised stock options to purchase 150,000 shares of common stock at $3.00 per share and stock options to purchase 33,333 shares of common stock at $1.71 per share. The stock options were exercised pursuant to “cashless” exercise provisions wherein the intrinsic value of the stock options were delivered to the Company in lieu of cash payment of the exercise price and, as a result, the Company issued an aggregate of 73,354 shares of common stock pursuant to the exercise of the stock options.
During the year ended December 31, 2011, stock options to purchase 45,000 shares of common stock at prices ranging from $0.36 to $1.71 were exercised for cash proceeds totaling $43,200.
In January 2012, a non-executive employee exercised stock options to purchase 10,000 shares of common stock at $3.00 per share. The stock options were exercised pursuant to “cashless” exercise provisions wherein the intrinsic value of the stock options were delivered to the Company in lieu of cash payment of the exercise price and, as a result, the Company issued an aggregate of 5,275 shares of common stock pursuant to the exercise of the stock options.
In March 2012, the Company’s board of directors approved a stock option grant to purchase an aggregate of 5,000 shares of common stock to a non-executive employee. The options are exercisable for a term of seven years at $6.40 per share and vest ½ on the date of grant and ½ on the first anniversary of the grant date. The grant date value of the options was $31,850. The options were valued using the Black-Scholes model with the following assumptions: 296% volatility; 3.75 year estimated life; zero dividends; 0.64% discount rate; and, quoted stock price and exercise price of $6.40.
F-30
In April 2012, a non-executive employee exercised stock options to purchase 25,000 shares of common stock at $1.53 per share. The stock options were exercised pursuant to “cashless” exercise provisions wherein the intrinsic value of the stock options were delivered to the Company in lieu of cash payment of the exercise price and, as a result, the Company issued an aggregate of 19,650 shares of common stock pursuant to the exercise of the stock options.
In May 2012, a non-employee director exercised stock options to purchase 35,000 shares of common stock at $2.80 per share. The stock options were exercised pursuant to “cashless” exercise provisions wherein the intrinsic value of the stock options were delivered to the Company in lieu of cash payment of the exercise price and, as a result, the Company issued an aggregate of 20,174 shares of common stock pursuant to the exercise of the stock options.
In June 2012, the Company’s board of directors approved stock option grants to purchase an aggregate of 105,000 shares of common stock to non-employee directors. The options are exercisable for a term of seven years at $6.65 per share and vest ½ on the date of grant and ½ on the first anniversary of the grant date. The grant date value of the options was $695,100. The options were valued using the Black-Scholes model with the following assumptions: 292% volatility; 3.75 year estimated life; zero dividends; 0.50% discount rate; and, quoted stock price and exercise price of $6.65.
During the year ended December 31, 2012, stock options to purchase 163,500 shares of common stock at prices ranging from $1.53 to $3.00 were exercised for cash proceeds totaling $405,255.
Stock based compensation expense attributable to common shares and grants of options was $1,205,919, $943,119 and $2,570,145 during the years ended December 31, 2012, 2011 and 2010, respectively. The unamortized amount of stock-based compensation that had not been recorded was $517,646 and $1,226,285 as of December 31, 2012 and 2011, respectively.
The following table presents the options outstanding at December 31, 2012:
| Number of Shares Underlying Options |
| Weighted Average Exercise Price per Share |
| Weighted Average Grant Date Fair Value per Share |
| Weighted Average Remaining Contractual Life (in Years) |
| Aggregate Intrinsic Value (1) | ||||
Outstanding at December 31, 2009 |
| 75,000 |
|
| 0.36 |
|
| 0.18 |
| 8.2 |
|
| 141,750 |
Granted |
| 1,292,500 |
|
| 2.53 |
|
| 2.53 |
| 8.6 |
|
| 265,550 |
Exercised |
| - |
|
| - |
|
| - |
| - |
|
| - |
Forfeited |
| (350,000) |
|
| 1.64 |
|
| 2.93 |
| - |
|
| - |
Outstanding at December 31, 2010 |
| 1,017,500 |
| $ | 2.24 |
| $ | 2.23 |
| 8.3 |
| $ | 407,300 |
Granted |
| 395,000 |
|
| 4.19 |
|
| 4.19 |
| 7.2 |
|
| 1,228,350 |
Exercised |
| (228,333) |
|
| 2.41 |
|
| 2.36 |
| - |
|
| - |
Forfeited |
| (201,667) |
|
| 1.71 |
|
| 1.48 |
| - |
|
| - |
Outstanding at December 31, 2011 |
| 982,500 |
| $ | 3.09 |
| $ | 3.07 |
| 7.6 |
| $ | 4,133,025 |
Granted |
| 110,000 |
|
| 6.64 |
|
| 6.61 |
| 0.6 |
|
| - |
Exercised |
| (233,500) |
|
| 2.45 |
|
| 2.38 |
| - |
|
| - |
Forfeited |
| (75,000) |
|
| 4.26 |
|
| 4.26 |
| - |
|
| - |
Outstanding at December 31, 2012 |
| 784,000 |
|
| 3.66 |
|
| 3.65 |
| 6.5 |
|
| 474,240 |
Exercisable at December 31, 2012 |
| 555,666 |
| $ | 3.20 |
| $ | 3.19 |
| 6.6 |
| $ | 431,639 |
(1)
The intrinsic value of an option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the warrant. On December 31, 2012, the last reported sales price of our common stock on the NYSE MKT was $3.54 per share.
F-31
The following table summarizes information about stock options outstanding and exercisable at December 31, 2012:
Options Outstanding and Exercisable | ||||||||
Exercise Price |
| Number of Shares Underlying Options |
| Weighted Average Exercise Price per Share |
| Weighted Average Remaining Contractual Life (in Years) | ||
$ | 0.36 |
| 50,000 |
| $ | 0.03 |
| 0.6 |
| 1.39 |
| 10,000 |
|
| 0.03 |
| 0.1 |
| 1.53 |
| 33,166 |
|
| 0.09 |
| 0.5 |
| 1.71 |
| 2,500 |
|
| 0.01 |
| - |
| 2.75 |
| 10,000 |
|
| 0.05 |
| 0.2 |
| 2.80 |
| 35,000 |
|
| 0.18 |
| 0.3 |
| 3.00 |
| 255,000 |
|
| 1.38 |
| 3.3 |
| 3.05 |
| 35,000 |
|
| 0.19 |
| 0.3 |
| 4.59 |
| 50,000 |
|
| 0.41 |
| 0.5 |
| 4.62 |
| 10,000 |
|
| 0.08 |
| 0.1 |
| 5.11 |
| 10,000 |
|
| 0.09 |
| 0.1 |
| 6.40 |
| 2,500 |
|
| 0.03 |
| - |
| 6.65 |
| 52,500 |
|
| 0.63 |
| 0.6 |
|
|
| 555,666 |
| $ | 3.20 |
| 6.6 |
Warrant Activity
In April 2010, the Company sold to a service provider, for a purchase price of $100, a warrant to purchase 40,000 shares of the Company’s common stock. The grant date value of the warrants was $120,000 and recorded as legal expense. The warrants are exercisable at $3.00 per share for a term of five years and are vested immediately. The warrants were valued using the Black-Scholes model with the following assumptions: $3.00 quoted stock price; $3.00 exercise price; 352% volatility; 5 year estimated life; zero dividends; 2.61% discount rate.
Pursuant to the terms of the Company’s plan of reorganization, in May 2010, the Company issued to Wayzata a warrant (the “Wayzata 2010 Warrants”) to purchase 2,000,000 shares of common stock. The warrants vested as to 111,111 shares on exit from bankruptcy (May 14, 2010) and, thereafter, vested as to 111,111 shares per month until April 2012. The fair value of the warrants of $4,099,116 was recorded as a debt discount to long-term debt. The warrants were exercisable at $0.01 per share for a term of five years. The warrants were valued using the Black-Scholes model with the following assumptions: $2.05 quoted stock price; $0.01 exercise price; 397% volatility; 5 year estimated life; zero dividends; 0.85% discount rate.
In April 2011, the Company entered into a Warrant Termination Agreement with Wayzata. Under the terms of the Warrant Termination Agreement, Wayzata agreed, subject to the Company’s repayment by July 14, 2011 of all amounts owing under the existing credit facilities with Wayzata, to the cancellation of the Wayzata 2010 Warrants. Upon closing of the July 2011 note placement and retirement of all amounts owing to Wayzata, in July 2011, the Wayzata 2010 Warrants were cancelled resulting in a gain of $10.6 million relating to the unamortized balance of the fair value of the warrants (see Note 4 – “Debt – Retirement of the Wayzata Debt”).
Pursuant to the April 2011 private placement of units of common stock and warrants, the Company issued warrants to purchase 1,240,658 shares of common stock. The warrants are exercisable for two years to purchase shares of common stock at $5.00 per share. In connection with the private placement, the company issued to a placement agent a warrant to purchase 42,300 shares of common stock on identical terms to the warrants sold in the private placement.
In September 2011, Wayzata exercised a warrant, originally issued in July 2008, to purchase 805,516 shares of common stock at $0.01 per share. The warrant was exercised pursuant to a “cashless” exercise provision wherein the intrinsic value of the warrant was delivered to the Company in lieu of cash payment of the exercise price and, as a result, the Company issued an aggregate of 803,764 shares of common stock pursuant to the exercise of the warrant.
In December 2011, a service provider exercised a warrant, originally issued in May 2008, to purchase 250,000 shares of common stock at $0.25 per share. The warrant was exercised pursuant to a “cashless” exercise provision wherein the intrinsic value of the warrant was delivered to the Company in lieu of cash payment of the exercise price and, as a result, the Company issued an aggregate of 239,984 shares of common stock pursuant to the exercise of the warrant.
F-32
In January 2012, an investor exercised a warrant, originally issued in April 2011, to purchase 500,000 shares of common stock at $5.00 per share for proceeds of $2,500,000.
In May 2012, investors exercised warrants, originally issued in April 2011, to purchase 213,996 shares of common stock at $5.00 per share for proceeds of $1,069,980. In conjunction with the exercise of these warrants, the Company granted three year warrants to purchase an aggregate of 106,997 shares of common stock at $8.00 per share.
In June and July 2012, investors exercised warrants, originally issued in April 2011, to purchase 178,331 shares of common stock at $5.00 per share for proceeds of $891,655.
The following table presents the warrants outstanding at December 31, 2012:
| Number of Shares Underlying Warrants |
| Weighted Average Exercise Price per Share |
| Weighted Average Grant Date Fair Value per Share |
| Weighted Average Remaining Contractual Life (in Years) |
| Aggregate Intrinsic Value (1) | ||||
Outstanding at December 31, 2009 |
| 1,090,516 |
|
| 0.08 |
|
| 1.99 |
| 2.5 |
|
| 2,370,506 |
Granted |
| 2,040,000 |
|
| 0.07 |
|
| 2.07 |
| 4.3 |
|
| 4,480,000 |
Exercised |
| - |
|
| - |
|
| - |
| - |
|
| - |
Forfeited |
| - |
|
| - |
|
| - |
| - |
|
| - |
Outstanding at December 31, 2010 |
| 3,130,516 |
| $ | 0.07 |
| $ | 2.03 |
| 3.7 |
| $ | 6,850,506 |
Granted |
| 1,282,958 |
|
| 5.00 |
|
| 2.66 |
| 1.4 |
|
| 2,950,803 |
Exercised |
| (1,055,516) |
|
| 0.07 |
|
| 2.01 |
| - |
|
| - |
Forfeited |
| (2,000,000) |
|
| 0.01 |
|
| 2.05 |
| - |
|
| - |
Outstanding at December 31, 2011 |
| 1,357,958 |
| $ | 4.82 |
| $ | 2.61 |
| 1.4 |
| $ | 3,365,703 |
Granted |
| 106,997 |
|
| 8.00 |
|
| 6.20 |
| 0.4 |
|
| - |
Exercised |
| (892,327) |
|
| 5.00 |
|
| 2.65 |
| - |
|
| - |
Forfeited |
| - |
|
| - |
|
| - |
| - |
|
| - |
Outstanding at December 31, 2012 |
| 572,628 |
| $ | 5.14 |
| $ | 3.22 |
| 0.8 |
| $ | 132,900 |
Exercisable at December 31, 2012 |
| 572,628 |
| $ | 5.14 |
| $ | 3.22 |
| 0.8 |
| $ | 132,900 |
(1)
The intrinsic value of a warrant is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the warrant. On December 31, 2012, the last reported sales price of our common stock on the NYSE MKT was $3.54 per share.
The following table summarizes information about stock warrants outstanding and exercisable at December 31, 2012:
Warrants Outstanding and Exercisable | ||||||||
Exercise Price |
| Number of Shares Underlying Warrants |
| Weighted Average Exercise Price per Share |
| Weighted Average Remaining Contractual Life (in Years) | ||
$ | 0.17 |
| 30,000 |
| $ | 0.01 |
| - |
| 1.50 |
| 5,000 |
|
| 0.01 |
| - |
| 3.00 |
| 40,000 |
|
| 0.21 |
| 0.2 |
| 5.00 |
| 390,631 |
|
| 3.41 |
| 0.2 |
| 8.00 |
| 106,997 |
|
| 1.50 |
| 0.4 |
|
|
| 572,628 |
| $ | 5.14 |
| 0.8 |
NOTE 12. INCOME TAXES
The Company is subject to income tax in the United States. Current tax obligations associated with our provision for income taxes are reflected in the accompanying Balance Sheet as component of “Accrued liabilities” and the deferred tax obligations are reflected in “Deferred income taxes”.
Our effective tax rates were different than our federal statutory tax rate due to state income taxes associated with income from various locations in which we have operations. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, the timing, amount, and location of future production and future operating expenses and capital costs.
Our provision (benefit) for income taxes at December 31, 2012 and 2011 consisted of the following:
F-33
|
| 2012 |
| 2011 | ||
Current: |
|
|
|
|
|
|
Federal |
| $ | 87,513 |
| $ | - |
State |
|
| 113,682 |
|
| (291,155) |
|
|
| 201,195 |
|
| (291,155) |
|
|
|
|
|
|
|
Deferred: |
|
|
|
|
|
|
Federal |
|
| (1,951,613) |
|
| (6,547,962) |
State |
|
| - |
|
| - |
|
|
| (1,951,613) |
|
| (6,547,962) |
Total tax provision (benefit) |
| $ | (1,750,418) |
| $ | (6,839,117) |
The U.S. federal statutory income tax rate is reconciled to the effective rate at December 31, 2012 and 2011 as follows:
|
| 2012 |
| 2011 |
Income tax expense at U.S. federal statutory rate |
| 35.0 % |
| 35.0 % |
Valuation allowance |
| - |
| (69.9)% |
State and local income taxes, net of federal income tax benefit |
| - |
| 3.3 % |
Permanent differences |
| (1.0)% |
| (20.1)% |
Temporary differences |
| (1.9)% |
| 2.6 % |
Effective tax rate |
| 32.1 % |
| (49.1)% |
The components of the net deferred tax assets (liabilities) at December 31, 2012 and 2011 are as follows:
| 2012 |
| 2011 | ||
Deferred tax asset |
|
|
|
|
|
Net operating loss | $ | 15,603,753 |
| $ | 8,152,044 |
Stock-based compensation |
| 2,379,770 |
|
| 1,918,506 |
Debt issuance cost (amortization) |
| 1,360,620 |
|
| 1,309,041 |
Depreciation and amortization |
| (25,671) |
|
| 8,971 |
Capital loss carryover |
| 103,752 |
|
| 103,752 |
Charitable contributions |
| 15,942 |
|
| 7,048 |
Total deferred tax assets |
| 19,438,166 |
|
| 11,499,362 |
Deferred tax liability |
|
|
|
|
|
Depletion on oil and gas properties |
| 10,938,591 |
|
| 4,951,400 |
Total deferred tax liabilities |
| 10,938,591 |
|
| 4,951,400 |
Less: valuation allowance |
| - |
|
| - |
Deferred tax asset (liability) | $ | 8,499,575 |
| $ | 6,547,962 |
At December 31, 2012, we had $40.8 million of federal net operating loss, or NOL, carryforwards; the federal NOL carryforwards have expiration dates through the year 2032.
We recognize the expected future tax benefit from deferred tax assets when the tax benefit is considered to be more likely than not of being realized. Otherwise, a valuation allowance is applied against deferred tax assets reducing the value of such assets. Assessing the recoverability of deferred tax assets requires management to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecasted income from operations and the application of existing tax laws in each jurisdiction. Oil and gas price estimates are a key component used in the determination of our ability to realize the expected future benefit of our deferred tax assets. To the extent that future taxable income differs significantly from estimates as a result of a decline in oil and gas prices or other factors, our ability to realize the deferred tax assets could be impacted. Additionally, significant future issuances of common stock or common stock equivalents could limit our ability to utilize our net operating loss carryforwards pursuant to Section 382 of the Internal Revenue Code. Future changes in tax law or changes in ownership structure could limit our ability to utilize our recorded tax assets. As of December 31, 2011, we removed substantially all deferred tax valuation allowances related to net operating loss carryforwards.
F-34
NOTE 13. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION - UNAUDITED
Supplemental quarterly financial information is as follows:
| Quarter Ended | ||||||||||
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
2012 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues | $ | 20,217,928 |
| $ | 24,113,983 |
| $ | 16,717,445 |
| $ | 22,963,119 |
Net income (loss) |
| (1,219,074) |
|
| 860,285 |
|
| (475,003) |
|
| (2,873,837) |
Net income (loss) per share, basic |
| (0.04) |
|
| 0.03 |
|
| (0.02) |
|
| (0.10) |
Net income (loss) per share, diluted | $ | (0.04) |
| $ | 0.03 |
| $ | (0.02) |
| $ | (0.10) |
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues | $ | 16,947,038 |
| $ | 21,056,204 |
| $ | 19,824,335 |
| $ | 23,106,573 |
Net income (loss) |
| 358,237 |
|
| 2,068,902 |
|
| 6,171,918 |
|
| 12,246,884 |
Net income (loss) per share, basic |
| 0.02 |
|
| 0.11 |
|
| 0.25 |
|
| 0.57 |
Net income (loss) per share, diluted | $ | 0.02 |
| $ | 0.09 |
| $ | 0.24 |
| $ | 0.58 |
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues | $ | 12,691,034 |
| $ | 13,682,755 |
| $ | 13,678,410 |
| $ | 14,966,016 |
Net income (loss) |
| (5,833,834) |
|
| (8,363,373) |
|
| (3,523,767) |
|
| (1,720,554) |
Net income (loss) per share, basic |
| (0.35) |
|
| (0.49) |
|
| (0.21) |
|
| (0.09) |
Net income (loss) per share, diluted | $ | (0.35) |
| $ | (0.49) |
| $ | (0.21) |
| $ | (0.09) |
NOTE 14. SUPPLEMENTAL OIL AND GAS DISCLOSURES - UNAUDITED
Capitalized costs for our oil and gas producing activities consisted of the following at December 31, 2012 and 2011:
| 2012 |
| 2011 | ||
Proved properties | $ | 260,916,084 |
| $ | 196,101,827 |
Unproved properties |
| - |
|
| - |
|
| 260,916,084 |
|
| 196,101,827 |
Accumulated depreciation, depletion, amortization and impairment |
| (81,056,770) |
|
| (53,345,814) |
Net capitalized costs | $ | 179,859,314 |
| $ | 142,756,013 |
Costs incurred for oil and gas property acquisitions, exploration and development for the years ended December 31, 2012 and 2011 are as follows:
| 2012 |
| 2011 | ||
Acquisitions of properties: |
|
|
|
|
|
Proved | $ | - |
| $ | 569,425 |
Unproved |
| - |
|
| - |
Exploration and dry hole costs |
| 640,545 |
|
| 4,508,888 |
Development |
| 59,815,686 |
|
| 25,898,062 |
| $ | 60,456,231 |
| $ | 30,976,375 |
F-35
The following table sets forth the consolidated results of operations for the years ended December 31, 2012, 2011 and 2010:
| 2012 |
| 2011 |
| 2010 | |||
Oil and gas revenues | $ | 82,528,932 |
| $ | 76,159,268 |
| $ | 52,734,207 |
Lease operating expense |
| (19,317,283) |
|
| (17,123,890) |
|
| (13,774,406) |
Workover expense |
| (3,828,197) |
|
| (2,666,600) |
|
| (2,154,482) |
Exploration expense |
| (547,192) |
|
| (596,065) |
|
| (1,921,943) |
Loss on plugging and abandonment |
| (2,468,969) |
|
| (393,599) |
|
| - |
Dry hole costs |
| (93,353) |
|
| (3,912,823) |
|
| - |
Depreciation, depletion, amortization and impairment |
| (27,809,452) |
|
| (16,232,839) |
|
| (16,001,826) |
Accretion expense |
| (1,510,165) |
|
| (1,672,900) |
|
| (1,668,268) |
Gain on revision of asset retirement obligations |
| 245,007 |
|
| 303,633 |
|
| - |
Severance taxes |
| (7,768,426) |
|
| (6,090,666) |
|
| (5,214,677) |
Income before income taxes |
| 19,430,902 |
|
| 27,773,519 |
|
| 11,998,605 |
Income tax benefit (provision) |
| 1,750,418 |
|
| 6,839,117 |
|
| (285,838) |
Results of operations for oil and gas producing activities (excluding Corporate overhead and financing costs) | $ | 21,181,320 |
| $ | 34,612,636 |
| $ | 11,712,767 |
Proved Oil and Gas Reserves
Proved oil and gas reserves were estimated by independent petroleum engineers. The reserves were based on the following assumptions:
·
Future revenues were based on an unweighted 12-month average of the first-day-of-the-month price held constant throughout the life of the properties.
·
Production and development costs were computed using year-end costs assuming no change in present economic conditions.
·
Future net cash flows were discounted at an annual rate of 10%.
Reserve estimates are inherently imprecise and these estimates are expected to change as future information becomes available.
F-36
The following summarizes our estimated total net proved reserves for the years in the three-year period ended December 31, 2012:
|
| Gas (Mcf) |
| Oil (Bbls) |
| Boe |
For the year ended December 31, 2010 |
|
|
|
|
|
|
Beginning of year |
| 62,247,900 |
| 7,578,100 |
| 17,952,751 |
Acquisition of reserves |
| 887,679 |
| 252,047 |
| 399,994 |
Discoveries and extensions |
| - |
| - |
| - |
Improved recovery |
| - |
| - |
| - |
Revisions |
| (377,179) |
| 598,253 |
| 535,390 |
Production |
| (1,882,800) |
| (550,000) |
| (863,800) |
End of year |
| 60,875,600 |
| 7,878,400 |
| 18,024,335 |
Proved developed reserves |
|
|
|
|
|
|
Beginning of year |
| 9,387,400 |
| 2,984,800 |
| 4,549,367 |
End of year |
| 5,112,400 |
| 2,656,600 |
| 3,508,667 |
|
|
|
|
|
|
|
For the year ended December 31, 2011 |
|
|
|
|
|
|
Beginning of year |
| 60,875,600 |
| 7,878,400 |
| 18,024,335 |
Acquisition of reserves |
| 1,717,000 |
| 172,900 |
| 459,067 |
Discoveries and extensions |
| 1,456,000 |
| 18,400 |
| 261,067 |
Improved recovery |
| - |
| - |
| - |
Revisions |
| 3,951,000 |
| 511,200 |
| 1,169,700 |
Production |
| (2,038,000) |
| (605,900) |
| (945,567) |
End of year |
| 65,961,600 |
| 7,975,000 |
| 18,968,602 |
Proved developed reserves |
|
|
|
|
|
|
Beginning of year |
| 5,112,400 |
| 2,656,600 |
| 3,508,667 |
End of year |
| 10,101,000 |
| 2,580,600 |
| 4,264,100 |
|
|
|
|
|
|
|
For the year ended December 31, 2012 |
|
|
|
|
|
|
Beginning of year |
| 65,961,600 |
| 7,975,000 |
| 18,968,602 |
Acquisition of reserves |
| - |
| - |
| - |
Discoveries and extensions |
| - |
| - |
| - |
Improved recovery |
| - |
| - |
| - |
Revisions |
| (10,403,800) |
| 1,108,000 |
| (625,968) |
Production |
| (2,639,500) |
| (676,400) |
| (1,116,317) |
End of year |
| 52,918,300 |
| 8,406,600 |
| 17,226,317 |
Proved developed reserves |
|
|
|
|
|
|
Beginning of year |
| 10,101,000 |
| 2,580,600 |
| 4,264,100 |
End of year |
| 9,159,500 |
| 2,809,200 |
| 4,335,783 |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information was developed utilizing procedures prescribed by Accounting Standards Codification 932-235 (ASC 932-235), “Disclosures about Oil and Gas Producing Activities.” The information is based on estimates prepared by independent petroleum engineers. The “standardized measure of discounted future net cash flows” should not be viewed as representative of the current value of our proved oil and gas reserves. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.
In reviewing the information that follows, we believe that the following factors should be taken into account:
•
future costs and sales prices will probably differ from those required to be used in these calculations;
•
actual production rates for future periods may vary significantly from the rates assumed in the calculations;
•
a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil and gas revenues; and
•
future net revenues may be subject to different rates of income taxation.
F-37
Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices applicable to our reserves to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of open hedge positions. Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate and year-end prices and costs are required by ASC 932-235.
In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible outcomes.
The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows:
(dollars in thousands) | 2012 |
| 2011 |
| 2010 | |||
Future cash inflows | $ | 1,102,848 |
| $ | 1,210,125 |
| $ | 934,061 |
Future production costs |
| (258,251) |
|
| (281,429) |
|
| (209,593) |
Future development costs |
| (232,806) |
|
| (226,552) |
|
| (239,510) |
Future net cash flows before income taxes |
| 611,791 |
|
| 702,144 |
|
| 484,958 |
Future income tax expense |
| (171,671) |
|
| (207,555) |
|
| (130,490) |
Future net cash flows before 10% discount |
| 440,120 |
|
| 494,589 |
|
| 354,468 |
10% annual discount for estimating timing of cash flows |
| (147,435) |
|
| (163,705) |
|
| (118,811) |
Standardized measure of discounted future net cash flows | $ | 292,685 |
| $ | 330,884 |
| $ | 235,657 |
Set forth in the table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves:
(dollars in thousands) | 2012 |
| 2011 |
| 2010 | |||
Beginning of year | $ | 330,884 |
| $ | 235,657 |
| $ | 145,586 |
Sales of oil and gas produced, net of production costs |
| (51,615) |
|
| (49,945) |
|
| (31,270) |
Net change in prices and production costs |
| (2,218) |
|
| 108,942 |
|
| 135,389 |
Extension, discoveries, and improved recovery, less related costs |
| - |
|
| 16,128 |
|
| - |
Development costs incurred during the year |
| 20,993 |
|
| 7,088 |
|
| - |
Net change in estimated future development costs |
| (19,437) |
|
| 7,493 |
|
| (49,840) |
Revisions of previous quantity estimates |
| (20,211) |
|
| 37,107 |
|
| 13,943 |
Net change from acquisitions of minerals in place |
| - |
|
| 16,861 |
|
| 3,689 |
Net change in income taxes |
| 19,232 |
|
| (53,119) |
|
| (1,919) |
Accretion of discount |
| 46,431 |
|
| 31,597 |
|
| 22,398 |
Changes in timing and other |
| (31,374) |
|
| (26,925) |
|
| (2,319) |
End of year | $ | 292,685 |
| $ | 330,884 |
| $ | 235,657 |
NOTE 15. SUBSEQUENT EVENTS
In January 2013, the Company received gross proceeds of $9,945 for 6,500 stock options exercised at $1.53 a share.
In January 2013, the Company entered into a fixed price hedge agreement with Cargill, Incorporated for a total of 159,500 barrels of crude oil at $109.20 per barrel for the period from April 2013 through March 2014.
In January 2013, the Company entered into a fixed price hedge agreement with Koch Supply & Trading, LP for a total of 122,500 barrels of crude oil at $106.82 per barrel for the period from April 2013 through December 2013.
In March 2013, the Company bid on, and was the apparent high bidder relative to, four leases, with seismic maps included, totaling 19,814 acres in the Central Gulf of Mexico Lease Sale 227. The acreage is in the shallow Gulf of Mexico shelf in water depths of 13 to 77 feet. Two of the leases are in the Vermilion area and two of the leases are in the Ship Shoal area. Final award of the leases is subject to BOEMRE review. Lease bonuses on the prospects total $880,000 and first year annual rentals of $138,698. Additionally, assuming final award of the leases, the Company will pay a prospect fee of $450,000 to a third party consultant.
F-38
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 20. Indemnification of Directors and Officers.
Texas
Saratoga Resources, Inc., Lobo Resources, Inc. and Lobo Operating, Inc. are each corporations organized under the laws of the State of Texas.
Our articles of incorporation, and the articles of incorporation of Lobo Resources, Inc. and Lobo Operating, Inc., contain a provision that limits the liability of directors as permitted by the Texas Business Organizations Code. The provision eliminates the personal liability of a director to the respective company and shareholders thereof for monetary damages for an act or omission in the director’s capacity as a director. The provision does not change the liability of a director for breach of his duty of loyalty to us or to our shareholders, for an act or omission not in good faith that involves intentional misconduct or a knowing violation of law, for an act or omission for which the liability of a director is expressly provided for by an applicable statute, or in respect of any transaction from which a director received an improper personal benefit. Pursuant to the articles of incorporation, the liability of directors will be further limited or eliminated without action by shareholders if Texas law is amended to further limit or eliminate the personal liability of directors.
Our bylaws, and the bylaws of Lobo Resources, Inc. and Lobo Operating, Inc., provide for the indemnification of officers and directors, and the advancement to them of expenses in connection with proceedings and claims, to the fullest extent permitted by the Texas Business Organizations Code.
In addition, we have purchased directors’ and officers’ liability insurance policies for our directors and officers.
Louisiana
Harvest Oil & Gas, LLC and The Harvest Group LLC are each limited liability companies organized under the laws of the State of Louisiana.
Section 12:1315 of the Louisiana Business Corporation Law, or the LBCL, provides that the articles of organization or a written operating agreement of a limited liability company may eliminate or limit the personal liability of a member or members, if management is reserved to the members, or a manager or managers, if management is vested in one or more managers pursuant to Section 12:1312 of the LBCL, for monetary damages for breach of any duty provided for in Section 12:1314 of the LBCL or provide for indemnification of a member or members, or a manager or managers, for judgments, settlements, penalties, fines, or expenses incurred because he is or was a member or manager. No provision of LBCL shall limit or eliminate the liability of a member or manager for the amount of a financial benefit received by a member or manager to which he is not entitled or for an intentional violation of a criminal law.
The Amended and Restated Operating Agreements of Harvest Oil & Gas, LLC and The Harvest Group LLC each provide that the company shall indemnify any person who was or is a party defendant or is threatened to be made a party defendant to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the company), by reason of the fact that he is or was a member of the company, an operating manager, an officer, employee or agent of the company, or is or was serving at the request of the company, against expenses (including attorney’s fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with the action, suit or proceeding if the members determine that he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interest of the company, and with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. The termination of any action, suit, or proceeding by judgment, order, settlement, conviction, or on a plea of nolo contender or its equivalent, will not in itself create a presumption that the person did or did not act in good faith and interest of the company and, with respect to any criminal action or proceeding, had reasonable cause to believe that his conduct was unlawful.
II-1
Item 21. Exhibits and Financial Statement Schedules.
|
|
|
| Incorporated by Reference |
|
| ||||
Exhibit Number |
|
|
| Filed Herewith | ||||||
| Exhibit Description |
| Form |
| Date Filed |
| Number | |||
3.1 |
| Restated Articles of Incorporation of Saratoga Resources with amendments, dated May 14, 2010 |
| 8-K |
| 05/18/10 |
| 3.1 |
|
|
3.2 |
| Amended and Restated Bylaws of Saratoga Resources, dated May 16, 2011 |
| 8-K |
| 05/20/11 |
| 3.1 |
|
|
4.1 |
| Indenture Agreement, dated July 12, 2011, by and among Saratoga Resources and The Bank of New York Mellon Trust Company, N.A., as trustee |
| 8-K |
| 07/15/11 |
| 4.1 |
|
|
4.2 |
| First Supplemental Indenture, dated December 4, 2012, by and among Saratoga Resources and The Bank of New York Mellon Trust Company, N.A., as trustee |
| 8-K |
| 12/05/12 |
| 4.1 |
|
|
4.3 |
| Indenture, dated November 22, 2013, by and among Saratoga Resources and The Bank of New York Mellon Trust Company, N.A., as trustee |
| 8-K |
| 11/25/13 |
| 4.1 |
|
|
4.4 |
| Intercreditor Agreement, dated November 22, 2013, by and among Saratoga Resources, the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee on behalf of holders of First Lien Notes, and The Bank of New York Mellon Trust Company, N.A., as trustee on behalf of holders of Second Lien Notes |
| 8-K |
| 11/25/13 |
| 4.2 |
|
|
4.5 |
| Form of Registration Rights Agreement, dated November 22, 2013, by and among Saratoga Resources, the guarantors named therein and the purchasers of First Lien Notes |
| 8-K |
| 11/25/13 |
| 4.3 |
|
|
5.1 |
| Opinion of Adams and Reese LLP |
|
|
|
|
|
|
| X |
10.1 |
| Employment Agreement, dated June 10, 2013, with Thomas Cooke* |
| 8-K |
| 06/14/13 |
| 10.1 |
|
|
10.4 |
| Employment Agreement, dated June 10, 2013, with Andrew Clifford* |
| 8-K |
| 06/14/13 |
| 10.2 |
|
|
10.7 |
| Investor Rights Agreement, dated July 12, 2011 |
| 8-K |
| 07/15/11 |
| 10.3 |
|
|
10.8 |
| Saratoga Resources, Inc. 2011 Omnibus Incentive Plan |
| S-8 |
| 09/13/11 |
| 10.1 |
|
|
10.9 |
| Form of Warrant Exercise Agreement |
| 8-K |
| 05/25/12 |
| 10.1 |
|
|
10.10 |
| Form of $8.00 Warrant |
| 8-K |
| 05/25/12 |
| 10.2 |
|
|
10.11 |
| Saratoga Resources, Inc. Annual Incentive Plan* |
| 8-K |
| 03/23/12 |
| 10.1 |
|
|
10.12 |
| Form of Share Purchase Agreement, dated May 14, 2012 |
| 8-K |
| 05/16/12 |
| 10.1 |
|
|
10.13 |
| Form of Subscription Agreement, dated May 14, 2012 |
| 8-K |
| 05/16/12 |
| 10.2 |
|
|
10.14 |
| Form of Registration Rights Agreement, dated May 2012 |
| 8-K |
| 05/16/12 |
| 10.3 |
|
|
14.1 |
| Code of Ethics for CEO and Senior Financial Officers |
| 10-KSB |
| 01/25/06 |
| 14.1 |
|
|
21.1 |
| List of subsidiaries |
| 10-K |
| 04/14/10 |
| 21.1 |
|
|
23.1 |
| Consent of MaloneBailey, LLP |
|
|
|
|
|
|
| X |
23.2 |
| Consent of Collarini Associates |
|
|
|
|
|
|
| X |
23.3 |
| Consent of DeGolyer and MacNaughton |
|
|
|
|
|
|
| X |
23.4 |
| Consent of Adams and Reese LLP (included in Exhibit 5.1) |
|
|
|
|
|
|
| X |
24.1 |
| Powers of Attorney (included on signature pages) |
| S-4 |
| 01/13/14 |
| 24.1 |
|
|
25.1 |
| Form T-1 Statement of Eligibility of Trustee with respect to the Indenture. |
| S-4 |
| 01/13/14 |
| 25.1 |
|
|
99.1 |
| Form of Letter of Transmittal |
| S-4 |
| 01/13/14 |
| 99.1 |
|
|
99.2 |
| Reserve Report of Independent Engineer – Collarini |
| 10-K |
| 04/01/13 |
| 99.1 |
|
|
99.3 |
| Reserve Report of Independent Engineer – DeGolyer and MacNaughton |
| 8-K |
| 12/13/13 |
| 99.1 |
|
|
*
Compensatory plan or arrangement.
II-2
Item 22. Undertakings
The undersigned Registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:
| (i) | to include any prospectus required by Section 10(a)(3) of the Securities Act of 1933; |
| (ii) | to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and |
| (iii) | to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement; |
provided, however, that paragraphs (i), (ii) and (iii) do not apply if the information required to be included in a post-effective amendment by those paragraphs is contained in reports filed with or furnished to the SEC by the Registrant pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the registration statement, or is contained in a form of prospectus filed pursuant to Rule 424(b) that is part of the registration statement.
(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.
(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser:
| (i) | Each prospectus filed by the Registrant pursuant to Rule 424(b)(3) shall be deemed to be part of the registration statement as of the date the filed prospectus was deemed part of and included in the registration statement; and |
| (ii) | Each prospectus required to be filed pursuant to Rule 424(b)(2), (b)(5) or (b)(7) as part of a registration statement in reliance on Rule 430B relating to an offering made pursuant to Rule 415(a)(1)(i), (vii) or (x) for the purpose of providing the information required by Section 10(a) of the Securities Act of 1933 shall be deemed to be part of and included in the registration statement as of the earlier of the date such form of prospectus is first used after effectiveness or the date of the first contract of sale of securities in the offering described in the prospectus. As provided in Rule 430B, for liability purposes of the issuer and any person that is at that date an underwriter, such date shall be deemed to be a new effective date of the registration statement relating to the securities in the registration statement to which the prospectus relates, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such effective date, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such effective date. |
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(5) That, for the purpose of determining liability of the Registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned Registrant undertakes that in a primary offering of securities of the undersigned Registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned Registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:
| (i) | Any preliminary prospectus or prospectus of the undersigned Registrant relating to the offering required to be filed pursuant to Rule 424; |
| (ii) | Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned Registrant or used or referred to by the undersigned Registrant; |
| (iii) | The portion of any other free writing prospectus relating to the offering containing material information about the undersigned Registrant or its securities provided by or on behalf of the undersigned Registrant; and |
| (iv) | Any other communication that is an offer in the offering made by the undersigned Registrant to the purchaser. |
(6) That, for purposes of determining any liability under the Securities Act of 1933, each filing of the Registrant’s annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to Section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
(7) To file an application for the purpose of determining the eligibility of the trustee to act under subsection (a) of Section 310 of the Trust Indenture Act in accordance with the rules and regulations prescribed by the SEC under Section 305(b)(2) of the Trust Indenture Act.
(8) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the claim has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.
(9) The Registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of Form S-4, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.
(10) The Registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction that was not the subject of and included in the registration statement when it became effective.
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, each of the registrants certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on February 11, 2014.
SARATOGA RESOURCES, INC. |
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By: | /s/ Thomas F. Cooke |
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| Thomas F. Cooke |
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| Chairman and Chief Executive Officer |
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Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities indicated on February 11, 2014.
SIGNATURE |
| TITLE |
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/s/ Thomas F. Cooke |
| Chairman, Chief Executive Officer and |
Thomas F. Cooke |
| Director (Principal Executive Officer) |
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| President and Director |
Andrew C. Clifford |
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| Controller |
Randal McDonald |
| (Principal Accounting Officer) |
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| Vice President – Finance and Business Development |
John Ebert |
| (Principal Financial Officer) |
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| Director |
John W. Rhea, IV |
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| Director |
Rex H. White, Jr. |
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| Director |
Kevin Smith |
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Thomas F. Cooke, by signing his name hereto, does hereby sign and execute this registration statement on behalf of the above-named officers and directors of Saratoga Resources, Inc. pursuant to powers of attorney previously filed with the Securities and Exchange Commission.
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, each of the registrants certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on February 11, 2014.
LOBO RESOURCES, INC. |
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By: | /s/ Thomas F. Cooke |
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| Thomas F. Cooke |
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| Chairman and Chief Executive Officer |
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Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities indicated on February 11, 2014.
SIGNATURE |
| TITLE |
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/s/ Thomas F. Cooke |
| President and Director |
Thomas F. Cooke |
| (Principal Executive Officer and Principal Accounting Officer) |
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, each of the registrants certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on February 11, 2014.
LOBO OPERATING, INC. |
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By: | /s/ Thomas F. Cooke |
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| Thomas F. Cooke |
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| Chairman and Chief Executive Officer |
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Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities indicated on February 11, 2014.
SIGNATURE |
| TITLE |
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/s/ Thomas F. Cooke |
| President and Director |
Thomas F. Cooke |
| (Principal Executive Officer and Principal Accounting Officer) |
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, each of the registrants certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on February 11, 2014.
HARVEST OIL & GAS, LLC |
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By: | /s/ Thomas F. Cooke |
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| Thomas F. Cooke |
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| Operating Manager |
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Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities indicated on February 11, 2014.
SIGNATURE |
| TITLE |
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/s/ Thomas F. Cooke |
| Operating Manager |
Thomas F. Cooke |
| (Principal Executive Officer and Principal Accounting Officer) |
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, each of the registrants certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on February 11, 2014.
THE HARVEST GROUP LLC |
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By: | /s/ Thomas F. Cooke |
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| Thomas F. Cooke |
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| Operating Manager |
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Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities indicated on February 11, 2014.
SIGNATURE |
| TITLE |
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/s/ Thomas F. Cooke |
| Operating Manager |
Thomas F. Cooke |
| (Principal Executive Officer and Principal Accounting Officer) |
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