UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2011
or
o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission file number 001-31539
SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Delaware (State or other jurisdiction of incorporation or organization) | 41-0518430 (I.R.S. Employer Identification No.) |
1775 Sherman Street, Suite 1200, Denver, Colorado (Address of principal executive offices) | 80203 (Zip Code) |
(303) 861-8140
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
Common stock, $.01 par value | New York Stock Exchange | |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesþ Noo
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ
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 þ | Accelerated filer o |
Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the 63,229,780 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the Company’s common stock on June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, of $73.48 per share, as reported on the New York Stock Exchange; was $4,646,124,234. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the Company to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
As of February 16, 2012, the registrant had 64,114,366 shares of common stock outstanding, which is net of 81,067 treasury shares held by the registrant.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2012 annual meeting of stockholders to be filed within 120 days after December 31, 2011.
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PART I
When we use the terms “SM Energy,” “the Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under Glossary of Oil and Gas Terms. Throughout this document we make statements that may be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this document for an explanation of these types of statements.
ITEMS 1. and 2. BUSINESS and PROPERTIES
General
We are an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids (also referred to as "oil", "gas", and "NGLs" throughout the document) in onshore North America, with a current focus on oil and liquids-rich resource plays. We were founded in 1908 and incorporated in Delaware in 1915. Our initial public offering of common stock was in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.”
Our principal offices are located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140.
Strategy
Our business strategy is focused on the early capture of resource plays in order to create and then enhance value for our shareholders, while maintaining a strong balance sheet. We strive to leverage industry leading exploration and leasehold acquisition teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have captured potential value through these efforts, our goal is to develop such potential through top tier operational and project execution. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to improve our returns and preserve our financial strength.
Significant Developments in 2011
• | Resource Play Delineation and Development Results in Record Production and Increase in Year-End Proved Reserve Estimates. Our estimated proved reserves increased 28 percent to 1,259.2 BCFE at December 31, 2011, from 984.5 BCFE at December 31, 2010. We added 526.1 BCFE through drilling activity during the year, which was primarily led by our efforts in the Eagle Ford shale in South Texas, the Bakken/Three Forks plays in North Dakota, and the Haynesville shale in East Texas. We achieved record levels of production in 2011. Our average daily production was composed of 274.8 MMcf of gas, 22.1 MBbl of oil, and 9.6 MBbl of NGLs for an average equivalent production rate of 465.0 MMCFE per day, which was an increase of 54 percent from 301.4 MMCFE per day in 2010. Costs incurred in 2011 for drilling and exploration activities and acquisitions increased 77 percent, to $1.6 billion, compared with $877.4 million in 2010. The increase in capital investment reflects increased confidence in our drilling inventory, particularly in plays with significant oil and NGL-rich gas components, such as our Eagle Ford shale and Bakken/Three Forks plays. Please refer to Core Operational Areas below for additional discussion concerning our 2011 estimated proved reserves, production, and capital investment. |
• | Acquisition and Development Agreement. In December 2011, we closed on our Acquisition and Development Agreement with Mitsui E&P Texas LP ("Mitsui"), an indirect subsidiary of Mitsui & Co. Ltd., which transferred 12.5 percent of our working interest in certain non-operated oil and gas assets in South Texas. Under the agreement, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs for wells targeting the Eagle Ford shale attributable to our remaining interests in these assets, until Mitsui has expended an aggregate of $680.0 million on our behalf. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement in Part II, Item 8 of this report for additional discussion concerning this transaction. |
• | Financing Activities. During 2011, our financing activities consisted of the following transactions: |
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• | issuance of $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2019 ("6.625% Senior Notes"); |
• | issuance of $350.0 million in aggregate principal amount of 6.50% Senior Notes due 2021 ("6.50% Senior Notes"); and |
• | execution of a $2.5 billion Fourth Amended and Restated Credit Agreement with a borrowing base of $1.3 billion and lender commitments of $1.0 billion, as of December 31, 2011. |
Please refer to Note 5 - Long-term Debt in Part II, Item 8 of this report for additional discussion regarding our financing arrangements.
• | Impairments. We recognized $219.0 million of proved property impairments for the year ended December 31, 2011. A significant decrease in natural gas prices during the second half of 2011 led to the impairment of certain dry gas assets in our ArkLaTex region. |
• | Divestiture Activity. We continuously look to improve the quality of our asset portfolio through the divestiture of non-strategic properties. Our divestiture activity helps to generate cash that can be used to fund the development of assets with higher potential value and for other general corporate purposes. Often, but not always, we divest of properties with higher operating costs and/or limited future drilling or development potential. During 2011, we sold 93.1 BCFE of reserves, the majority of which related to assets located in our South Texas & Gulf Coast region. The following transactions represent our most significant divestitures during 2011: |
• | Eagle Ford Shale Divestiture. In August 2011, we completed the divestiture of certain operated Eagle Ford shale assets located in our South Texas & Gulf Coast region. This position comprised our entire operated acreage in LaSalle County, Texas, as well as an immaterial adjacent block of our operated acreage in Dimmit County, Texas. Total divestiture proceeds, before marketing costs, Net Profits Interest Bonus Plan ("Net Profits Plan") payments, and legal fees (referred to subsequently as "divestiture proceeds"), were $230.8 million. The estimated gain on this divestiture was $194.6 million and post-closing adjustments, if any, are expected to be finalized in the first quarter of 2012. |
• | Mid-Continent Divestiture. In June 2011, we completed the divestiture of certain non-strategic assets located in our Mid-Continent region. Total divestiture proceeds were $35.8 million. The estimated gain on this divestiture was $28.5 million and post-closing adjustments, if any, are expected to be finalized in the first quarter of 2012. |
• | Rocky Mountain Divestiture. In January 2011, we completed the divestiture of certain non-strategic assets located in our Rocky Mountain region. Total divestiture proceeds were $45.5 million. The final gain on this divestiture was $27.2 million. |
Outlook for 2012
We enter 2012 with a capital program expected to be in the range of approximately $1.4 billion to $1.5 billion, of which approximately $1.2 billion to $1.3 billion will be allocated to drilling and completion activities focused primarily on the development of our inventory of resource play opportunities. Please refer to Core Operational Areas below for detailed discussion of our 2012 capital budget by region and Outlook for 2012 under Part II, Item 7 of this report for additional discussion surrounding our capital plans for 2012.
As we enter 2012, we are well positioned both financially and operationally. From a financial perspective, we believe that we are adequately capitalized and have sufficient liquidity to fund our planned capital expenditures for this year. Operationally, we have secured the majority of the drilling rigs and services required to execute our 2012 business plan.
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Core Operational Areas
Our operations are concentrated in five core operating areas in the onshore United States. The following table summarizes estimated proved reserves, PV-10 reserve value, and production for the year ended December 31, 2011, for our core operating areas:
ArkLaTex | Mid- Continent | South Texas & Gulf Coast | Permian | Rocky Mountain | Total(1) | ||||||||||||||||||
Proved Reserves | |||||||||||||||||||||||
Oil (MMBbl) | 0.3 | 0.8 | 14.6 | 12.4 | 43.7 | 71.7 | |||||||||||||||||
Gas (Bcf) | 124.0 | 223.9 | 243.0 | 31.7 | 41.5 | 664.0 | |||||||||||||||||
NGLs (MMBbl) | 0.9 | 1.0 | 25.5 | 0.2 | — | 27.5 | |||||||||||||||||
Equivalents (BCFE) | 130.6 | 234.6 | 483.6 | 107.0 | 303.4 | 1,259.2 | |||||||||||||||||
Relative percentage | 10 | % | 19 | % | 38 | % | 9 | % | 24 | % | 100 | % | |||||||||||
Proved Developed % | 76 | % | 75 | % | 54 | % | 86 | % | 71 | % | 67 | % | |||||||||||
PV-10 Values (in millions) (2) | |||||||||||||||||||||||
Proved Developed | $ | 173.7 | $ | 353.9 | $ | 857.7 | $ | 459.8 | $ | 991.2 | $ | 2,836.3 | |||||||||||
Proved Undeveloped (3) | 16.9 | 42.3 | 294.5 | 51.4 | 219.8 | 624.9 | |||||||||||||||||
Total Proved | $ | 190.6 | $ | 396.2 | $ | 1,152.2 | $ | 511.2 | $ | 1,211 | $ | 3,461.2 | |||||||||||
Relative percentage | 6 | % | 11 | % | 33 | % | 15 | % | 35 | % | 100 | % | |||||||||||
Production | |||||||||||||||||||||||
Oil (MMBbl) | 0.1 | 0.4 | 2.6 | 1.3 | 3.7 | 8.1 | |||||||||||||||||
Gas (Bcf) | 29.3 | 28.6 | 34.7 | 3.5 | 4.2 | 100.3 | |||||||||||||||||
NGLs (MMBbl) | 0.1 | 0.1 | 3.2 | — | — | 3.5 | |||||||||||||||||
Equivalent (BCFE) | 30.1 | 31.6 | 69.7 | 11.5 | 26.7 | 169.7 | |||||||||||||||||
Avg. Daily Equivalents (MMCFE/d) | 82.5 | 86.7 | 191.1 | 31.5 | 73.3 | 465.0 | |||||||||||||||||
Relative percentage | 18 | % | 19 | % | 41 | % | 6 | % | 16 | % | 100 | % | |||||||||||
(1) | Totals may not sum due to rounding. |
(2) | The standardized measure PV-10 calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown in the Reserves section below. |
(3) | We record estimates of proved undeveloped reserves for locations with a positive PV-0 value when we have the intent to drill the location and it meets our economic criteria. |
South Texas & Gulf Coast Region. Operations for the South Texas & Gulf Coast region are managed from our office in Houston, Texas. Our current operations in this region focus primarily on our Eagle Ford shale program. Our acreage position covers a significant portion of the western Eagle Ford shale play, including acreage in the oil, the NGL-rich gas, and the dry gas windows of the play. We entered 2011 with approximately 250,000 net acres in the play, which was comprised of an approximate 165,000 net acre operated position in Webb, Dimmit, and LaSalle Counties, Texas and an approximate 85,000 net acre non-operated position in Maverick, Dimmit, LaSalle, and Webb Counties, Texas. During the year we reduced our acreage in two separate transactions. The first transaction was a sale of approximately 15,400 net operated acres in LaSalle and Dimmit Counties, Texas to Talisman Energy USA Inc. and Statoil Texas Onshore Properties LLC (collectively, "Talisman/Statoil") for $225.0 million, which closed in August 2011. The second transaction, which reduced our working interest from approximately 27.0 percent to approximately 14.5 percent, was our assignment of approximately 39,000 net acres in our non-operated program to Mitsui in exchange for Mitsui's agreement to carry 90 percent of our drilling and completion costs until Mitsui has expended $680.0 million for our benefit. This transaction closed in December 2011. These two transactions allowed us to consolidate our operating foot print in the play and, by divesting of a significant piece of our non-operated program, put a greater percentage of our capital expenditures in this play under our operational control. As of December 31, 2011, we have roughly 196,000 net acres in the play.
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Approximately 75 percent of this acreage is operated by us with an average working interest of nearly 100 percent. On our operated acreage position, we increased our rig count over the course of the year from two rigs at the beginning of the year to five drilling rigs by year end. During the year, we also increased our contracted firm transportation capacity for our operated wet gas volumes to approximately 225 MMcf from approximately 100 MMcf. In 2012, our firm transportation capacity will continue to increase, which we expect will allow us to exit the year with approximately 270 MMcf of gross wet gas firm transportation capacity. In our non-operated Eagle Ford shale program, the operator of the program increased its rig count from seven at the beginning of 2011 to ten by year-end. We participated in substantially all of the drilling activity in the non-operated Eagle Ford shale program during the year. Additionally, we participated as a co-owner in the construction of midstream assets that service our non-operated acreage in the play.
Nearly all of our capital deployed in the South Texas & Gulf Coast region in 2011 targeted our Eagle Ford shale program. Our capital investment, production, and reserves all increased significantly in 2011 as a result of our focused efforts in our Eagle Ford shale program, which has become a critical growth driver of production and reserve growth for the Company. Our capital expenditures for exploration, development, and acquisition activities in our South Texas & Gulf Coast region increased significantly from $456.2 million in 2010 to $932.3 million in 2011. Production in 2011 was 69.7 BCFE, an increase of 207 percent over the 22.7 BCFE produced in 2010. Estimated proved reserves at the end of 2011 increased 133 percent to 483.6 BCFE from 207.3 BCFE in the prior year, while reflecting the reduction of 70.2 BCFE of proved reserves as a result of our transactions with Mitsui and Talisman/Statoil. Of the reserve additions in the region, approximately 353.3 BCFE of proved reserves were added through drilling activities. The increase in production and proved reserves reflects the significant increase in activity in our Eagle Ford shale program throughout the year.
Our plan for 2012 in the South Texas & Gulf Coast region is to continue focusing primarily on the Eagle Ford shale. At the beginning of 2012, we had five operated rigs, two of which are designed for pad drilling. We expect to operate five to six drilling rigs throughout 2012, with an increasing number of those rigs being capable of pad drilling. We believe that we have sufficient access to drilling rigs and completion services to execute our plan for the year. A significant portion of the gas takeaway capacity we will need for 2012 has been secured under firm transportation contracts. In the non-operated portion of our Eagle Ford shale position, the operator has indicated that it plans to operate approximately ten drilling rigs throughout 2012.
We have allocated a range of $650 million to $700 million of our 2012 capital budget to our operated Eagle Ford shale drilling program. Most of our drilling and completion costs in the non-operated portion of our Eagle Ford shale program will be carried by Mitsui during 2012 under the terms of our Acquisition and Development Agreement with Mitsui, although we will be responsible for our proportionate share of any infrastructure investments made in this program.
Rocky Mountain Region. Operations for our Rocky Mountain region are managed from our office in Billings, Montana. Our capital expenditures in 2011 primarily targeted the Bakken/Three Forks formations in the North Dakota portion of the Williston Basin, where we have approximately 87,000 net acres. In 2011, we were successful in testing prospects farther west and north of our prior development activity in North Dakota. In our Raven and Bear Den prospects, our efforts have largely centered on optimizing our completions and spacing for development of the Bakken formation. In our Gooseneck prospect in Divide County, North Dakota, our efforts have been focused on the Three Forks formation. Elsewhere in the Rocky Mountain region, we drilled several test wells in the Niobrara formation in Wyoming during the year. At year-end 2011, we had 91,000 net acres with potential for the Niobrara and other formations in the northern DJ and Powder River Basins.
Our capital expenditures for exploration, development, and acquisition activity in our Rocky Mountain region increased from $158.5 million in 2010 to $288.0 million in 2011, as we accelerated our activity in the Bakken/Three Forks formations and commenced testing of our Niobrara acreage. Estimated proved reserves for our Rocky Mountain region were 303.4 BCFE at year-end 2011, compared with 231.8 BCFE as of the end of 2010, a 31 percent increase over 2010. During the year, we added approximately 105.3 BCFE of proved reserves through drilling activities. Our program targeting the Bakken/Three Forks formations contributed the majority of our proved reserve additions in this region. Total regional production for 2011 was up seven percent to 26.7 BCFE,
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despite weather related delays throughout the region, including unusually severe spring flooding and wet weather which hindered production and drilling activity through the summer. As these issues subsided, we were able to increase activity and complete most of our planned activity for the year.
Our capital budget for operated Bakken/Three Forks activity in 2012 is a range of $160 million and $185 million. We expect to operate four rigs in the play, up from three rigs at the end of 2011. Our drilling activity will be focused on holding our acreage in the Raven and Gooseneck prospects and will also include infill wells in our Bear Den prospect along the Nesson Anticline. We also expect to participate in a number of Bakken/Three Forks projects with other operators. In addition to Bakken/Three Forks drilling, we plan to split one operated rig between our two prospect areas located in the northern DJ Basin and the Powder River Basin in Wyoming.
Mid-Continent Region. Operations for our Mid-Continent region are managed from our office in Tulsa, Oklahoma. Our current operations in the Mid-Continent region are primarily focused on the horizontal development of the Granite Wash formation in western Oklahoma. Our Mid-Continent region also manages our Woodford shale assets, on which we have minimized activity due to the low natural gas price environment. Our 2011 Granite Wash program targeted the shallower, more NGL-rich washes of our approximate 29,000 net acres in the play, the majority of which is held by production. In 2011, we incurred costs of $87.8 million in the Mid-Continent region for exploration, development, and acquisition activity, which is a 30 percent decrease from the $124.5 million incurred in 2010 for the region. In 2011, our Mid-Continent region's production was 31.6 BCFE, a decrease from the 33.4 BCFE produced in 2010. Proved reserves at the end of 2011 were 234.6 BCFE, a decrease of 20 percent from the 293.7 BCFE reported for 2010.
We plan to invest between $60 million and $70 million in 2012 in our operated horizontal Granite Wash program, with three operated drilling rigs planned to execute our drilling program for the year. No meaningful activity is required or expected in our Woodford shale program in 2012 due to our current outlook for natural gas prices. However, an increase in natural gas prices or a decrease in the costs of drilling and completing these wells could result in increased activity in the Woodford shale program.
ArkLaTex Region. Operations for our ArkLaTex region have historically been managed from our office in Shreveport, Louisiana. In the second half of 2011, we began consolidating our ArkLaTex and Mid-Continent regional offices into our office in Tulsa, Oklahoma. Our recent focus of the ArkLaTex region has been the horizontal development of our Haynesville shale acreage and achieving held by production status on our operated acreage position in East Texas. From a strategic standpoint, we believe holding this acreage, which is prospective for the Haynesville and Bossier shales, will provide value for us in the future if the economics for natural gas improve.
In 2011, we incurred costs of $159.2 million in the ArkLaTex region for exploration, development, and acquisition activity, which is a 234 percent increase from the $47.6 million incurred in 2010 for the region and is a result of our significant increase in capital expenditures in our operated Haynesville shale program to achieve held by production status. In 2011, production in our ArkLaTex region was 30.1 BCFE, a 109 percent increase from the 14.4 BCFE produced in 2010. Proved reserves at the end of 2011 were 130.6 BCFE, a decrease from the 137.9 BCFE reported for the prior year.
With the recent decline in natural gas prices, we have reduced our planned level of operated drilling activity in the Haynesville shale. Several operated wells that were previously planned for have been cut from the drilling schedule and we now expect to only invest between $35 million and $40 million on operated Haynesville shale drilling in 2012. This will result in the forfeiture of a small amount of operated acreage. After completing currently planned activity, we think that nearly 80 percent of our Haynesville acreage will be held by production, and we then plan to limit activity until gas prices recover or drilling costs lessen to a point that drilling projects meet our internal economic hurdles.
Permian Region. Operations for our Permian region are managed from our office in Midland, Texas. Our Permian region covers western Texas and eastern New Mexico. Our primary area of development focus in this region is the Wolfberry tight oil play, and we are actively working to delineate a newer exploratory play targeting
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the Mississippian limestone play.
We incurred costs of $80.7 million in the region for exploration, development, and acquisition activity in 2011 compared to $85.4 million in 2010. During the year, downspacing activity continued across our Wolfberry acreage. In addition, during 2011 we began testing acreage in Lynn, Borden, and Garza Counties, Texas targeting the vertical and horizontal development of the Mississippian limestone play. The region’s 2011 production was 11.5 BCFE, a decrease from 2010 production of 14.7 BCFE. The decrease in production was due to natural decline in the Wolfberry play as the field development matured and the number of remaining drilling locations on our acreage decreased. Proved reserves in this region as of the end of 2011 were 107.0 BCFE, which was a slight decline from 2010 year-end reserves of 113.9 BCFE.
During 2012, we plan to focus our Permian investment on further delineation of the Mississippian limestone play. A portion of our remaining capital allocated to this region will be spent on the development of our Wolfberry acreage.
Reserves
The table below presents summary information with respect to the estimates of our proved reserves for each of the years in the three-year period ended December 31, 2011. We engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit internal engineering estimates for at least 80 percent of the PV-10 value of our estimated proved reserves in each year presented. The prices used in the calculation of proved reserve estimates as of December 31, 2011, were $96.19 per Bbl for oil, $4.12 per MMBtu for natural gas, and $59.37 per Bbl for NGLs.
We emphasize that reserve estimates are inherently imprecise and that reserve estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved reserves owned by us. Neither prices nor costs have been escalated. The following table should be read along with the section entitled Risk Factors – Risks Related to Our Business contained herein. The actual quantities and present values of our estimated proved reserves may be less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year.
Our ability to replace our production is important to our sustainability. Please refer to the reserve replacement terms in the Glossary of Oil and Gas Terms section of this report for information describing how our reserve replacement metrics are calculated. Our reserve replacement percentages are calculated using information from the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information located in Part II, Item 8 of this report.
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We believe the concept of reserve replacement as described in the Glossary of Oil and Gas Terms section of this report, as well as permutations which may include other captions of the Oil and Gas Reserve Quantities section of Supplemental Oil and Gas Information located in Part II, Item 8 of this report, are widely understood by those who make investment decisions related to the oil and gas exploration business.
As of December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
Reserve data: | |||||||||||
Proved developed | |||||||||||
Oil (MMBbl) | 50.3 | 46.0 | 48.1 | ||||||||
Gas (Bcf) | 451.2 | 411.0 | 342.0 | ||||||||
NGLs (MMBbl) | 15.2 | - | - | ||||||||
BCFE | 844.0 | 687.3 | 630.3 | ||||||||
Proved undeveloped | |||||||||||
Oil (MMBbl) | 21.4 | 11.4 | 5.7 | ||||||||
Gas (Bcf) | 212.8 | 229.0 | 107.5 | ||||||||
NGLs (MMBbl) | 12.3 | - | - | ||||||||
BCFE | 415.2 | 297.2 | 141.9 | ||||||||
Total Proved | |||||||||||
Oil (MMBbl) | 71.7 | 57.4 | 53.8 | ||||||||
Gas (Bcf) | 664.0 | 640.0 | 449.5 | ||||||||
NGLs (MMBbl) | 27.5 | - | - | ||||||||
BCFE | 1,259.2 | 984.5 | 772.2 | ||||||||
Proved developed reserves % | 67 | % | 70 | % | 82 | % | |||||
Proved undeveloped reserves % | 33 | % | 30 | % | 18 | % | |||||
Reserve value data (in millions): | |||||||||||
Proved developed PV-10 | $ | 2,836.3 | $ | 2,053.5 | $ | 1,253.1 | |||||
Proved undeveloped PV-10 | 624.9 | 290.8 | 31.0 | ||||||||
Total proved PV-10 | $ | 3,461.2 | $ | 2,344.3 | $ | 1,284.1 | |||||
Standardized measure of discounted future cash flows | $ | 2,580.0 | $ | 1,666.4 | $ | 1,016.0 | |||||
Reserve replacement – drilling , excluding revisions | 310 | % | 349 | % | 100 | % | |||||
All in – including sales of reserves | 262 | % | 293 | % | 14 | % | |||||
All in – excluding sales of reserves | 317 | % | 372 | % | 55 | % | |||||
Reserve life (years) (1) | 7.4 | 8.9 | 7.1 | ||||||||
(1) Reserve life represents the estimated proved reserves at the dates indicated divided by actual production for the preceding 12-month period.
Note: NGL reserve data, production volumes, revenues, and prices for prior periods have not been reclassified to conform to the current presentation given the immateriality of the volumes in prior periods. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices under Part II, Item 7 of this report.
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The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 value (Non-GAAP). The difference is a result of the PV-10 value measure excluding the impact of income taxes. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the Glossary of Oil and Gas Terms.
As of December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(in millions) | |||||||||||
Standardized measure of discounted future net cash flows | $ | 2,580.0 | $ | 1,666.4 | $ | 1,016.0 | |||||
Add: 10 percent annual discount, net of income taxes | 1,727.6 | 1,294.6 | 733.0 | ||||||||
Add: future undiscounted income taxes | 1,740.4 | 1,335.5 | 515.9 | ||||||||
Undiscounted future net cash flows | $ | 6,048.0 | $ | 4,296.5 | $ | 2,264.9 | |||||
Less: 10 percent annual discount without tax effect | (2,586.8 | ) | (1,952.2 | ) | (980.8 | ) | |||||
PV-10 value | $ | 3,461.2 | $ | 2,344.3 | $ | 1,284.1 | |||||
Proved Undeveloped Reserves
As of December 31, 2011, we had 415.2 BCFE of proved undeveloped reserves, which is an increase of 118.0 BCFE, or 40 percent, over proved undeveloped reserves of 297.2 BCFE at December 31, 2010. We added 202.2 BCFE of proved undeveloped reserves through our drilling program, 187.5 BCFE of which were extensions and discoveries, primarily in the Eagle Ford shale and the Bakken/Three Forks plays, as well as an additional 14.7 BCFE of infill proved undeveloped reserves that were mostly concentrated in our assets in the Bakken/Three Forks formations, the Eagle Ford shale, and in our Wolfberry properties in our Permian region. A negative price revision of 33.4 BCFE was primarily due to gas weighted projects in our ArkLaTex and Mid-continent regions that no longer met internal economic investment hurdles for projects in which we would invest due to lower natural gas prices or that no longer generate positive cash flow utilizing 12-month average benchmark pricing required by the SEC. We had a net positive performance revision of 8.5 BCFE, which includes the impact of our conversion to three stream production reporting, as well as negative engineering revisions due primarily to higher than expected well costs in the Woodford shale in our Mid-Continent region, causing those projects to no longer meet our internal investment hurdles. During the year, we sold assets comprising 24.5 BCFE from our South Texas & Gulf Coast region. We invested $86.2 million to convert 34.6 BCFE of proved undeveloped reserves to proved reserves in 2011, mainly in the Eagle Ford and Haynesville shales and the Bakken/Three Forks formations.
As of December 31, 2011, we had no material proved undeveloped reserves that have been on our books in excess of five years, and we had recorded no material proved undeveloped locations that were more than one direct offset from an existing producing well. As of December 31, 2011, estimated future development costs relating to our proved undeveloped reserves are approximately $285 million, $289 million, and $266 million in 2012, 2013, and 2014, respectively.
Internal Controls Over Reserves Estimate
Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring the Company's proved reserves is delegated to our reservoir engineering group, which is managed by Dennis A. Zubieta, our Vice President - Engineering and Evaluation, subject to the oversight of our management and the Audit Committee of our Board of Directors, as discussed below.
Mr. Zubieta joined us in June 2000 as a Corporate Acquisition & Divestiture Engineer, assumed the role of Reservoir Engineer in February 2003, was appointed Reservoir Engineering Manager in August 2005, and was
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appointed Vice President - Engineering and Evaluation in August 2008. Mr. Zubieta was employed by Burlington Resources Oil and Gas Company from June 1988 to May 2000 in various operations and reservoir engineering capacities. Mr. Zubieta received a Bachelor of Science degree in Petroleum Engineering from Montana Tech in May 1988. Technical reviews are performed throughout the year by regional staff who evaluate geological and engineering data. This data, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. The regional technical staff does not report directly to Mr. Zubieta; they report to either regional technical managers or directly to the regional manager in their respective regions. This is intended to promote objective and independent analysis, within our regions as part of the reserves estimation process.
Third-party Reserves Audit
An independent audit is performed by Ryder Scott using their own engineering assumptions and economic and ownership data provided by us. A minimum of 80 percent of our total calculated proved reserve PV-10 value is audited by Ryder Scott. In the aggregate, the proved reserve values of our audited properties are required to be within ten percent of our valuations for the total company as well as for each respective region. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world for over seventy years. The technical person at Ryder Scott primarily responsible for overseeing our reserve audit is a Senior Vice President, who received a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970 and who is a registered Professional Engineer in Colorado and Utah. He is also a member of the Society of Petroleum Engineers. The Ryder Scott 2011 report concerning our reserves is included as Exhibit 99.1.
In addition to a third party audit, our reserves are reviewed by management and the Audit Committee of our Board of Directors. Management, which includes the President and Chief Executive Officer, the Executive Vice President and Chief Operating Officer, and the Executive Vice President and Chief Financial Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews the final reserves estimate in conjunction with Ryder Scott’s audit report. They may also meet with Ryder Scott representatives to discuss its processes and findings.
Production
The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced from properties in which we held an interest during the periods indicated. Realized prices presented below exclude the effects of hedges and derivative contracts. Also presented is a summary of production costs per MCFE:
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Years Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
Net production(1) | |||||||||||
Oil (MMBbl) | 8.1 | 6.4 | 6.3 | ||||||||
Gas (Bcf) | 100.3 | 71.9 | 71.1 | ||||||||
NGLs (MMBbl) | 3.5 | — | — | ||||||||
BCFE | 169.7 | 110.0 | 109.1 | ||||||||
Average net daily production(1) | |||||||||||
Oil (MBbl per day) | 22.1 | 17.4 | 17.3 | ||||||||
Gas (MMcf per day) | 274.8 | 196.9 | 194.8 | ||||||||
NGLs (MBbl per day) | 9.6 | — | — | ||||||||
MMCFE per day | 465.0 | 301.4 | 298.8 | ||||||||
Realized price | |||||||||||
Oil (per Bbl) | $ | 88.23 | $ | 72.65 | $ | 54.40 | |||||
Gas (per Mcf) | $ | 4.32 | $ | 5.21 | $ | 3.82 | |||||
NGLs (per Bbl) | $ | 53.32 | $ | — | $ | — | |||||
Per MCFE | $ | 7.85 | $ | 7.60 | $ | 5.65 | |||||
Production costs per MCFE | |||||||||||
Lease operating expense | $ | 0.88 | $ | 1.10 | $ | 1.33 | |||||
Transportation costs | $ | 0.51 | $ | 0.19 | $ | 0.19 | |||||
Production taxes | $ | 0.32 | $ | 0.48 | $ | 0.37 | |||||
(1) | In 2011 and 2010, total estimated proved reserves for our Eagle Ford shale properties equated to greater than 15 percent of our total proved reserves expressed on an equivalent basis. During 2011, our net production from the Eagle Ford shale was 32.9 Bcf of gas, 2.5 MMBbl of oil, and 3.1 MMBbl of NGLs or 66.6 BCFE. Our average daily production from the Eagle Ford shale was 90.1 MMcf of gas, 6.8 MBbl of oil, and 8.6 MBbl of NGLs, for an average production rate of 182.5 MMCFE per day. During 2010, our net production from the Eagle Ford shale was 13.0 Bcf of gas and 0.8 MMBbl of oil, or 17.6 BCFE. Our average daily production from the Eagle Ford shale was 35.6 MMcf of gas and 2.1 MBbl of oil, for an average production rate of 48.3 MMCFE per day. No fields contained 15 percent or greater of our total proved reserves expressed on an equivalent basis in 2009. |
Note: NGL reserve data, production volumes, revenues, and prices for prior periods have not been reclassified to conform to the current presentation given the immateriality of the volumes in prior periods. Please refer to additional discussion under the caption Oil, Gas, and NGL Prices under Part II, Item 7 of this report.
Productive Wells
As of December 31, 2011, we had working interests in 1,353 gross (741 net) productive oil wells and 2,928 gross (1,060 net) productive gas wells. Productive wells are either wells producing in commercial quantities or wells mechanically capable of commercial production, but are currently shut-in. Multiple completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.
Drilling Activity
All of our drilling activities are conducted using independent drilling contractors. We do not own any drilling equipment. The following table summarizes the number of operated and non-operated wells drilled and recompleted on our properties in 2011, 2010, and 2009, excluding any wells in which we own only a royalty interest:
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Years Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||
Development wells: | |||||||||||
Oil | 125 | 32.1 | 191 | 36.5 | 103 | 29.6 | |||||
Gas | 273 | 81.0 | 72 | 17.0 | 74 | 18.2 | |||||
Non-productive | 11 | 4.0 | 4 | 1.1 | 3 | 1.3 | |||||
409 | 117.1 | 267 | 54.6 | 180 | 49.1 | ||||||
Exploratory wells: | |||||||||||
Oil | 16 | 6.3 | 36 | 11.5 | 2 | 0.4 | |||||
Gas | 48 | 8.6 | 83 | 37.9 | 18 | 9.1 | |||||
Non-productive | 3 | 1.0 | 1 | 0.8 | 5 | 2.9 | |||||
67 | 15.9 | 120 | 50.2 | 25 | 12.4 | ||||||
Total | 476 | 133.0 | 387 | 104.8 | 205 | 61.5 | |||||
A productive well is an exploratory, development, or extension well that is producing oil, gas, and/or NGLs or that is capable of commercial production of those products. A dry well (hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil, gas, and/or NGLs in commercial quantities.
As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive and is part of a development project, which is defined as the means by which petroleum resources are brought to economically producible status. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for production of oil, gas, and/or NGLs, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
In addition to the wells drilled and completed in 2011 included in the table above, as of February 16, 2012, we were participating in the drilling of 34 gross wells. We operate 12 of these wells on a gross basis, seven on a net basis, with the remaining 22 gross wells, four on a net basis, being operated by others. With respect to completion activity, at such date, there were 156 gross wells in which we have an interest that were being completed. We operate 28 of these completion activities on a gross basis, 16 on a net basis, and were participating in 128 gross, 18 net non-operated completion activities. The vast majority, if not all, of these operations relate to the drilling of wells for primary production.
Acreage
The following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes held by us as of December 31, 2011. Undeveloped acreage includes leasehold interests that may already be classified as containing proved undeveloped reserves.
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Developed Acres (1) | Undeveloped Acres (2) | Total | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Louisiana | 70,632 | 26,049 | 16,367 | 4,716 | 86,999 | 30,765 | |||||||||||
Montana | 59,071 | 40,655 | 315,582 | 212,371 | 374,653 | 253,026 | |||||||||||
Nevada | - | - | 197,634 | 197,634 | 197,634 | 197,634 | |||||||||||
North Dakota | 134,647 | 88,865 | 158,543 | 87,186 | 293,190 | 176,051 | |||||||||||
Oklahoma | 257,348 | 82,962 | 39,280 | 14,334 | 296,628 | 97,296 | |||||||||||
Pennsylvania | 346 | 346 | 49,676 | 39,749 | 50,022 | 40,095 | |||||||||||
Texas | 211,525 | 135,211 | 489,922 | 226,543 | 701,447 | 361,754 | |||||||||||
Wyoming | 62,936 | 28,305 | 304,603 | 166,371 | 367,539 | 194,676 | |||||||||||
Other (3) | 4,430 | 2,011 | 53,418 | 34,351 | 57,848 | 36,362 | |||||||||||
800,935 | 404,404 | 1,625,025 | 983,255 | 2,425,960 | 1,387,659 | ||||||||||||
Louisiana Fee Properties | 10,499 | 10,499 | 14,415 | 14,415 | 24,914 | 24,914 | |||||||||||
Louisiana Mineral Servitudes | 7,426 | 4,217 | 4,769 | 4,407 | 12,195 | 8,624 | |||||||||||
17,925 | 14,716 | 19,184 | 18,822 | 37,109 | 33,538 | ||||||||||||
Total (4) | 818,860 | 419,120 | 1,644,209 | 1,002,077 | 2,463,069 | 1,421,197 | |||||||||||
(1) | Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above. |
(2) | Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves. |
(3) | Includes interest in Arkansas, Colorado, Illinois, Kansas, Mississippi, New Mexico, and Utah. |
(4) | As of the filing date, we had approximately 50,000, 73,000, and 65,000 net acres scheduled to expire by December 31, 2012, 2013, and 2014, respectively, if production is not established or we take no other action to extend the terms. |
Delivery Commitments
As of December 31, 2011, we had gathering, processing, and transportation through-put commitments with various parties that require us to deliver a fixed determinable quantity of product. We have an aggregate minimum commitment to deliver 1,766 Bcf of natural gas and 9 MMBbls of oil. These contracts expire at various dates through 2023. We will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume commitment for natural gas is projected, we have certain rights to arrange for third party gas to be delivered into the gathering lines and such volume will count towards our minimum commitment. At the current time, we do not have enough proved developed reserves to offset these contractual liabilities, but we expect to fulfill the delivery commitments with production from development of our proved reserves, as well as the development of resources not yet characterized as proved reserves, from our Eagle Ford shale and Haynesville shale resource plays. Therefore, we currently do not expect any shortfalls.
Major Customers
During 2011 and 2010, sales to Regency Gas Services LLC ("Regency") individually accounted for approximately 18 percent and 11 percent, respectively, of our total oil, gas, and NGL production revenue. During 2009, sales to Teppco Crude Oil LLC individually accounted for 12 percent of our total oil and gas production revenue.
Employees and Office Space
As of February 16, 2012, we had 639 full-time employees. None of our employees are subject to a collective bargaining agreement, and we consider our relations with our employees to be good. As of December 31, 2011, we leased approximately 84,000 square feet of office space in Denver, Colorado for our executive and administrative offices; approximately 39,000 square feet of office space in Tulsa, Oklahoma;
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approximately 30,000 square feet in Houston, Texas; approximately 30,000 square feet in Billings, Montana; approximately 25,000 square feet in Shreveport, Louisiana; approximately 22,000 square feet in Midland, Texas; approximately 7,000 total square feet in Williston and Watford City, North Dakota; and approximately 2,000 square feet in Casper, Wyoming.
Title to Properties
Substantially all of our interests are held pursuant to leases from third parties. A title opinion is usually obtained prior to the commencement of initial drilling operations. We have obtained title opinions or have conducted a title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The majority of our producing properties are subject to mortgages securing indebtedness under our credit facility, royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of, or affect the value of, such properties. We typically perform only minimal title investigation before acquiring undeveloped leasehold acreage.
Seasonality
Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. The impact of seasonality on oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of worldwide production capacity in excess of existing worldwide demand for oil. Certain of our drilling and completion operations are also subject to seasonal limitations. Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. See Risk Factors - Risks Related to Our Business for additional discussion.
Competition
The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe our leasehold position provides a sound foundation for a solid drilling program and our future growth. Our competitive position also depends on our geological, geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies, which in some cases have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs and other equipment, and generate electricity.
We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells. Consequently, we may face shortages or delays in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may be affected by future new energy, climate-related, financial, and/or other policies, legislation, and regulations.
In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other
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professionals. Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming more limited due to demographics in our industry. We are not insulated from the competition for quality people, and we must compete effectively in order to be successful.
Government Regulations
Our business is extensively regulated by numerous federal, state, and local laws and governmental regulations. These laws and regulations may be changed from time to time in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential of increasing our cost of doing business and, consequently, could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.
Energy Regulations. Many of the states in which we conduct our operations have adopted laws and regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations requiring permits for the drilling of wells, imposing bonding requirements in order to drill or operate wells, and governing the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to various state conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, state conservation laws sometimes establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management ("BLM"). These leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may suspend or terminate our operations on federal leases.
In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes may increase the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM.
Our sales of gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission ("FERC") has jurisdiction over the transportation and sale for resale of gas in interstate commerce. FERC's current regulatory framework generally provides for a competitive and open access market for sales and transportation of natural gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for gas production. In addition, the less stringent regulatory approach currently pursued by FERC and the United States Congress may not continue indefinitely.
Environmental, Health and Safety Matters
General. Our operations are subject to stringent and complex federal, state, tribal and local laws and regulations governing protection of the environment and worker health and safety as well as the discharge of materials into the environment. These laws and regulations may, among other things:
• | require the acquisition of various permits before drilling commences; |
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• | restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities; |
• | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and |
• | require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells. |
These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes that result in more stringent and costly permitting, waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.
The following is a summary of some of the existing laws, rules and regulations to which our business is subject.
Waste handling. The Resource Conservation and Recovery Act (the “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 (the “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 oil or natural gas are currently regulated under RCRA's non-hazardous waste provisions. However, 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 (“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 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.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination.
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Water discharges. The federal Water Pollution Control Act (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 and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, U.S. Army Corps of Engineers or analogous state agencies. 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.
The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability.
Air emissions. The federal Clean Air Act (“CAA”), and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the 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 CAA and associated state laws and regulations.
Climate change. 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 a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change could have an adverse effect on our operatives and the demand for oil and gas. See “Risk Factors - Risks Related to Our Business - Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas and NGLs.” In addition to the effects of regulation, the meteorological effects of global climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms and flooding, and could adversely affect the demand for our products.
Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our well drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas.
National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (the “NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay development of some of our oil and natural gas projects.
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OSHA and other laws and regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe that we are in substantial compliance with the applicable requirements of OSHA and comparable laws.
Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act's Underground Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation's public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas activities using hydraulic fracturing techniques which could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and delays which could adversely affect our financial position, results of operations and cash flows. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. While we believe that we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We cannot give any assurance that we will not be adversely affected in the future.
Cautionary Information about Forward-Looking Statements
This Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear in a number of places in this Form 10-K, and include statements about such matters as:
• | the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures; |
• | the drilling of wells and other exploration and development activities and plans, as well as possible future acquisitions; |
• | the possible divestiture or farm-down of, or joint venture relating to, certain properties; |
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• | proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates; |
• | future oil, gas, and NGL production estimates; |
• | our outlook on future oil, gas, and NGL prices, well costs, and service costs; |
• | cash flows, anticipated liquidity, and the future repayment of debt; |
• | business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and |
• | other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in Item 7 of this report. |
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. These risks are described in the Risk Factors section of this report, and include such factors as:
• | the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves; |
• | the continued weakness in economic conditions and uncertainty in financial markets; |
• | our ability to replace reserves in order to sustain production; |
• | our ability to raise the substantial amount of capital that is required to replace our reserves; |
• | our ability to compete against competitors that have greater financial, technical, and human resources; |
• | our ability to attract and retain key personnel; |
• | the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves; |
• | the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities; |
• | the possibility that exploration and development drilling may not result in commercially producible reserves; |
• | our limited control over activities on non-operated properties; |
• | our reliance on the skill and expertise of third-party service providers on our operated properties; |
• | the possibility that title to properties in which we have an interest may be defective; |
• | the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production; |
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• | the uncertainties associated with divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate; |
• | the uncertainties associated with enhanced recovery methods; |
• | our commodity derivative contracts may result in financial losses or may limit the prices that we receive for oil, gas, and NGL sales; |
• | the inability of one or more of our vendors, customers, or contractual counterparties to meet their obligations; |
• | price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values; |
• | the impact that lower oil, gas, or NGL prices could have on our ability to borrow under our credit facility; |
• | the possibility that our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt; |
• | operating and environmental risks and hazards that could result in substantial losses; |
• | complex laws and regulations, including environmental regulations, that result in substantial costs and other risks; |
• | the availability and capacity of gathering, transportation, processing, and/or refining facilities; |
• | our ability to sell and/or receive market prices for our oil, gas, and NGLs; |
• | new technologies may cause our current exploration and drilling methods to become obsolete; |
• | the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and |
• | litigation, environmental matters, the potential impact of government regulations, and the use of management estimates regarding such matters. |
We caution you that forward-looking statements are not guarantees of future performance and that actual results or performance may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this report speak as of the filing date of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws.
Available Information
Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website’s investor relations section we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. We also make available through our website’s corporate governance section our Corporate Governance Guidelines, Code of Business Conduct and Ethics, and the Charters for our Board of Directors’ Audit Committee, Compensation Committee, Executive Committee, and Nominating and Corporate Governance Committee. Information on our
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website is not incorporated by reference into this report and should not be considered part of this document.
Glossary of Oil and Gas Terms
The oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves, exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under SEC Rule 4-10(a) of Regulation S-X, as amended effective for fiscal years ending on or after December 31, 2009. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located through the SEC’s website at www.sec.gov.
Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet, used in reference to natural gas.
BCFE. Billion cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs.
BTU. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil, natural gas, and/or NGLs in commercial quantities.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and natural gas) rights.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Finding and development cost. Expressed in dollars per MCFE. Finding and development cost metrics provide information as to the cost of adding proved reserves from various activities, and are widely utilized within the exploration and production industry, as well as by investors. The information used to calculate these metrics is included in the Supplemental Oil and Gas Information section in Part II, Items 8 of this report. It should be noted that finding and development cost metrics have limitations. For example, exploration efforts related to a particular set of proved reserve additions may extend over several years. As a result, the exploration costs incurred in earlier periods are not included in the amount of exploration costs incurred during the period in which that set of proved reserves is added. In addition, consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. Since the additional development costs that will need to be incurred in
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the future before the proved undeveloped reserves are ultimately produced are not included in the amount of costs incurred during the period in which those reserves were added, those development costs in future periods will be reflected in the costs associated with adding a different set of reserves. The calculations of various finding and development cost metrics are explained below.
Finding and development cost – Drilling, excluding revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, during the same period.
Finding and development cost – Drilling, including revisions. Calculated by dividing the amount of costs incurred for development and exploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, and revisions of previous estimates, during the same period.
Finding and development cost – Drilling and acquisitions, excluding revisions. Calculated by dividing the amount of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, and acquisitions, during the same period.
Finding and development cost – Drilling and acquisitions, including revisions. Calculated by dividing the amount of costs incurred for development, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, revisions of previous estimates, and acquisitions, during the same period.
Finding and development cost –All in, including sales of reserves. Calculated by dividing the amount of total capital expenditures for oil and natural gas activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates less sales of reserves, during the same period.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Gross acre. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical.
Lease operating expenses. The expenses incurred in the lifting of crude oil, natural gas, and/or associated liquids from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet, used in reference to natural gas.
MCFE. One thousand cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs.
MMcf. One million cubic feet, used in reference to natural gas.
MMCFE. One million cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs.
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MMBtu. One million British thermal units.
Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells.
Net asset value per share. The result of the fair market value of total assets less total liabilities, divided by the total number of outstanding shares of common stock.
NGLs. The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressures and lower temperatures.
NYMEX WTI. New York Mercantile Exchange West Texas Intermediate.
OPIS. Oil Price Information Service Mont Belvieu.
PV-10 value (Non-GAAP). The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of ten percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period. This is a Non-GAAP measure.
Productive well. A well that is producing crude oil, natural gas, and/or NGLs or that is capable of commercial production of those products.
Proved reserves. Those quantities of oil, gas, and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Recompletion. The completion in an existing wellbore in a formation other than that in which the well has previously been completed.
Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period.
Reserve replacement. Reserve replacement metrics are used as indicators of a company’s ability to replenish annual production volumes and grow its reserves, and provide information related to how successful a company is at growing its proved reserve base. These are believed to be useful non-GAAP measures that are widely utilized within the exploration and production industry, as well as by investors. They are easily calculable metrics, and the information used to calculate these metrics is included in the Supplemental Oil and Gas Information section of Part II, Item 8 of this report. It should be noted that reserve replacement metrics have limitations. They are limited because they typically vary widely based on the extent and timing of new discoveries and property acquisitions. Their predictive and comparative value is also limited for the same reasons. In addition, because the metrics do not embed the cost or timing of future production of new reserves, they cannot be used as a measure of value creation.
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The calculations of various reserve replacement metrics are explained below.
Reserve replacement – Drilling, excluding revisions. Calculated as a numerator comprised of the sum of reserve extensions and discoveries and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity.
Reserve replacement – Drilling, including revisions. Calculated as a numerator comprised of the sum of reserve extensions, discoveries, and infill reserves, and revisions of previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling activity.
Reserve replacement – Drilling and acquisitions, excluding revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions and discoveries and infill reserves in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities.
Reserve replacement – Drilling and acquisitions, including revisions. Calculated as a numerator comprised of the sum of reserve acquisitions and reserve extensions, discoveries, and infill reserves, and revisions of previous estimates in an existing proved field divided by production for that same period. This metric is an indicator of the relative success a company is having in replacing its production through drilling and acquisition activities.
Reserve replacement percentage – All in, excluding sales of reserves. The sum of reserve extensions and discoveries, infill drilling, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period.
Reserve replacement percentage –All in, including sales of reserves. The sum of sales of reserves, infill drilling, reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil, natural gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Resource play. A term used to describe an accumulation of crude oil, natural gas, and/or associated liquid resources known to exist over a large areal expanse, which when compared to a conventional play typically has a lower expected geological and/or commercial development risk.
Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil, natural gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well.
Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of crude oil, natural gas, and NGL production free of costs of exploration, development, and production operations.
Seismic. The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface rock formations.
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a ten percent
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annual discount rate. The information for this calculation is included in the supplemental information regarding disclosures about oil and gas producing activities following the Notes to Consolidated Financial Statements included in this report.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.
Undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs.
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ITEM 1A. RISK FACTORS
In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an investment in us.
Risks Related to Our Business
Crude oil, natural gas, and NGL prices are volatile, and declines in prices adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow.
Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and natural gas properties depend heavily on the prices we receive for crude oil, natural gas and NGL sales. Crude oil, natural gas, and NGL prices also affect our cash flows available for capital expenditures and other items, our borrowing capacity, and the amount and value of our crude oil, natural gas, and NGL reserves. For example, the amount of our borrowing base under our credit facility is subject to periodic redeterminations based on crude oil, natural gas, and NGL prices specified by our bank group at the time of redetermination. In addition, we may have crude oil and natural gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly.
Historically, the markets for crude oil, natural gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in crude oil, natural gas, and NGL prices may result from relatively minor changes in the supply of and demand for crude oil, natural gas, and NGLs, market uncertainty, and other factors that are beyond our control, including:
• | global and domestic supplies of crude oil, natural gas, and NGLs, and the productive capacity of the industry as a whole; |
• | the level of consumer demand for crude oil, natural gas, and NGLs; |
• | overall global and domestic economic conditions; |
• | weather conditions; |
• | the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas that may affect the realized price for crude oil, natural gas, or NGLs; |
• | the price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural gas; |
• | the price and availability of alternative fuels; |
• | technological advances affecting energy consumption; |
• | the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain crude oil price and production controls; |
• | political instability or armed conflict in crude oil or natural gas producing regions; |
• | strengthening and weakening of the United States dollar relative to other currencies; and |
• | governmental regulations and taxes. |
These factors and the volatility of crude oil, natural gas, and NGL markets make it extremely difficult to predict future crude oil, natural gas, and NGL price movements with any certainty. Declines in crude oil, natural gas, and NGL prices would reduce our revenues and could also reduce the amount of crude oil, natural gas, and
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NGLs that we can produce economically, which could have a materially adverse effect on us.
Continued weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.
United States and global economies and financial systems have recently experienced turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, increased levels of unemployment, and an unprecedented level of intervention by the United States federal government and other governments. Although some portions of the economy appear to have stabilized and there have been signs of the beginning of a recovery, the extent and timing of a recovery, and whether it can be sustained, are uncertain. Continued weakness in the United States or other large economies could materially adversely affect our business and financial condition. For example:
• | the demand for crude oil, natural gas, and NGLs in the United States has declined and may remain at low levels or further decline if economic conditions remain weak, and continue to negatively impact our revenues, margins, profitability, operating cash flows, liquidity, and financial condition; |
• | natural gas prices have recently been lower than at various times in the last decade because of increased supply resulting from, among other things, increased drilling in unconventional reservoirs, reduced demand in connection with the recent recession, and an unusually warm winter, which sustained low prices could affect our financial condition and results of operations; |
• | the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables; |
• | the liquidity available under our credit facility could be reduced if any lender is unable to fund its commitment; |
• | our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for exploration and/or development of our reserves; |
• | our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and |
• | variable interest rate spread levels, including for LIBOR and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our credit facility. |
If we are unable to replace reserves, we will not be able to sustain production.
Our future operations depend on our ability to find, develop, or acquire crude oil, natural gas, and NGL reserves that are economically producible. Our properties produce crude oil, natural gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate and develop or acquire new crude oil, natural gas, and NGL reserves to replace those being depleted by production. In addition, competition for crude oil and natural gas properties is intense and many of our competitors have financial, technical, human, and other resources needed to evaluate and integrate acquisitions that are substantially greater than those available to us.
In the event we do complete an acquisition, its successful impact on our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price, future crude oil, natural gas, and NGL prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties, and future abandonment and
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possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.
Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions. Without successful drilling or acquisition activities, our reserves and production will decline over time.
Substantial capital is required to replace our reserves.
We must make substantial capital expenditures to find, acquire, develop, and produce crude oil, natural gas, and NGL reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for crude oil, natural gas, and NGL sales, our success in locating and developing and acquiring new reserves, and the orderly functioning of credit and capital markets. If crude oil, natural gas, and NGL prices decrease or if we encounter operating difficulties that result in our cash flows from operations being less than expected, we must reduce our capital expenditures unless we can raise additional funds through debt or equity financing or the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestitures may not always be of acceptable value to us.
If our revenues decrease due to lower crude oil, natural gas, or NGL prices, decreased production, or other reasons, and if we cannot obtain capital through our credit facility, other acceptable debt or equity financing arrangements, or through the sale of assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited.
Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do.
We face intense competition from major oil and gas companies, independent oil and natural gas exploration and production companies, financial buyers, and institutional and individual investors who seek crude oil and natural gas property investments throughout the world, as well as the equipment, expertise, labor, and materials required to operate crude oil and natural gas properties. Many of our competitors have financial, technical, and other resources vastly exceeding those available to us, and many crude oil and natural gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for development prospects and productive properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for the properties. In addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. We may not be successful in acquiring and developing profitable properties in the face of this competition.
We also compete for human resources. Over the last few years, the need for talented people across all disciplines in the industry has grown, while the number of talented people available has not grown at the same pace, and in many cases, is declining due to the demographics of the industry.
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The loss of key personnel could adversely affect our business.
We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of the services of these or other key personnel could adversely affect our business. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.
The actual quantities and present value of our proved crude oil, natural gas, and NGL reserves may be less than we have estimated.
This report and other of our SEC filings contain estimates of our proved crude oil, natural gas, and NGL reserves and the estimated future net revenues from those reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to crude oil, natural gas, and NGL prices, drilling and completion costs, operating expenses, capital expenditures, taxes, timing of operations, and availability of funds. The process of estimating crude oil, natural gas, and NGL reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent on many variables, and therefore changes often occur as our knowledge of these variables evolve. Therefore, these estimates are inherently imprecise. In addition, the reserve estimates we make for fields that do not have a lengthy production history may be less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing of development expenditures.
Actual future production, prices for crude oil, natural gas, and NGLs, revenues, production taxes, development expenditures, operating expenses, and quantities of producible crude oil, natural gas, and NGL reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities of and present value related to proved reserves disclosed by us, and the actual quantities and present value may be less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development activity, prevailing crude oil, natural gas, and NGL prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties.
As of December 31, 2011, 33 percent, or 415.2 BCFE, of our estimated proved reserves were proved undeveloped, and four percent, or 54.3 BCFE, were proved developed non-producing. In order to develop our proved undeveloped reserves, as of December 31, 2011, we estimate approximately $939 million of capital expenditures would be required. Production revenues from proved developed non-producing reserves will not be realized until sometime in the future and after some investment of capital. In order to bring production on-line for our proved developed non-producing reserves, as of December 31, 2011, we estimate capital expenditures of approximately $41 million will be deployed in future years. Although we have estimated our proved reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled, and actual results may not occur as estimated. A significant portion of our anticipated capital expenditures for 2012 is directed toward projects that are not yet classified within the construct of proved reserves as defined by Regulation S-X promulgated by the SEC.
You should not assume that the PV-10 value and standardized measure of discounted future net cash flows included in this report represent the current market value of our estimated proved crude oil, natural gas, and NGL reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. For example, values of our reserves as of December 31, 2011, were estimated using a calculated 12-month average sales price of $4.12 per MMBtu of natural gas (NYMEX Henry Hub spot price), $96.19 per Bbl of oil (NYMEX WTI spot price), and $59.37 per Bbl of NGL (OPIS spot price). We then adjust these base prices to reflect appropriate basis, quality, and location differentials over that period in estimating our proved reserves. During
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2011, our monthly average realized natural gas prices, excluding the effect of derivative cash settlements, were as high as $4.79 per Mcf and as low as $3.58 per Mcf. For the same period, our monthly average realized crude oil prices before the effect of derivative cash settlements were as high as $104.75 per Bbl and as low as $78.95 per Bbl, and were as high as $75.57 per Bbl and as low as $41.14 per Bbl for NGLs. Many other factors will affect actual future net cash flows, including:
• | amount and timing of actual production; |
• | supply and demand for crude oil, natural gas, and NGLs; |
• | curtailments or increases in consumption by oil purchasers and natural gas pipelines; and |
• | changes in government regulations or taxes, including severance and excise taxes. |
The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing the PV-10 value. In addition, the ten percent discount factor required by the SEC to be used to calculate the PV-10 value for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and natural gas industry in general are subject.
Proved reserve estimates as of December 31, 2011, 2010, and 2009 have been prepared under the SEC’s new rules for oil and gas reporting that were effective for fiscal years ending on or after December 31, 2009. These new rules require SEC reporting companies to prepare their proved reserve estimates using, among other things, revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing, instead of the prior requirement to use pricing at the end of the period. The SEC has released only limited interpretive guidance regarding reporting of proved reserve estimates under the new rules and may not issue further interpretive guidance on the new rules in the near future. The interpretation of these rules and their applicability in different situations remains unclear in many respects. Changing interpretations of the rules or disagreements with our interpretations could result in revisions to our proved reserve estimates, which could be significant.
Another impact of the SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells 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 programs. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill on those reserves within the required five-year timeframe. Substantial downward adjustments to our estimated proved reserves could have a material adverse effect on our financial condition, results of operations, and operating cash flows.
Our property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.
Successful property acquisitions require an assessment of a number of factors sometimes beyond our control. These factors include exploration potential, future crude oil, natural gas, and NGL prices, operating costs, and potential environmental and other liabilities. These assessments are not precise and their accuracy is inherently uncertain.
In connection with our acquisitions, we typically perform a customary review of the acquired properties that will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and
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warranties.
In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be limited.
Integrating acquired properties and businesses involves a number of other special risks, including the risk that management may be distracted from normal business concerns by the need to integrate operations and systems as well as retain and assimilate additional employees. Therefore, we may not be able to realize all of the anticipated benefits of our acquisitions.
We have limited control over the activities on properties we do not operate.
Some of our properties, including a portion of our operations in the Eagle Ford shale in South Texas, are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including the nature and timing of drilling and operational activities, the operator's skill and expertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, the selection and application of suitable technology, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs and materially and adversely affect our financial condition and results of operations.
We rely on third-party service providers to conduct the drilling operations on properties we operate.
Where we are the operator of a property, we rely on third-party service providers to perform the necessary drilling operations. The ability of third-party service providers to perform such drilling operations will depend on those service providers' ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, natural gas liquids and natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third-party service provider to adequately perform operations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results of operations.
Title to the properties in which we have an interest may be impaired by title defects.
We generally rely on title reports in acquiring oil and gas leasehold interests and obtain title opinions only on significant properties that we drill. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Title insurance is not available for oil and gas properties. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and title abstract facilities before attempting to acquire or place under lease a specific mineral interest and/or undertake drilling activities. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. Generally, under the terms of the operating agreements affecting our properties, any monetary loss attributable to a loss of title is to be borne by all parties to any such agreement in proportion to their interests in such property. A material title defect can reduce the value or render a property worthless, thus adversely affecting our financial condition, results of operations and operating cash flow if such property is of sufficient value.
Exploration and development drilling may not result in commercially producible reserves.
Crude oil and natural gas drilling and production activities are subject to numerous risks, including the risk that no commercially producible crude oil, natural gas, or associated liquids will be found. The cost of drilling and
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completing wells is often uncertain, and crude oil, natural gas or associated liquids drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
• | unexpected drilling conditions; |
• | title problems; |
• | disputes with owners or holders of surface interests on or near areas where we operate; |
• | pressure or geologic irregularities in formations; |
• | engineering and construction delays; |
• | equipment failures or accidents; |
• | hurricanes or other adverse weather conditions; |
• | compliance with environmental and other governmental requirements; and |
• | shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies. |
The prevailing prices for crude oil, natural gas, and NGLs affect the cost of and the demand for drilling rigs, completion and production equipment, and other related services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region. In addition, the recent economic and financial downturn has adversely affected the financial condition of some drilling contractors, which may constrain the availability of drilling services in some areas.
Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore on or develop our properties.
The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if crude oil, natural gas, or NGLs are present, or whether they can be produced economically. The cost of drilling, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling and completion costs.
Drilling results in our newer shale plays, such as the Eagle Ford and Haynesville shales, may be more uncertain than results in shale plays that are more developed and have longer established production histories. For example, our experience with horizontal drilling in these shales, as well as the industry’s drilling and production history, is more limited than in many shale plays, such as the Barnett or Woodford shales, and we and the industry generally have less information with respect to the ultimate recoverability of reserves and the production decline rates in these shales than other areas with longer histories of drilling and production. Completion techniques that have proven to be successful in other shale formations to maximize recoveries are being used in the early development of these new shales; however, we can provide no assurance of the ultimate success of these drilling
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and completion techniques.
In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such multi-year drilling inventories can be more susceptible to long-term uncertainties that could materially alter the occurrence or timing of actual drilling. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled, although we have the present intent to do so, or if we will be able to produce crude oil, natural gas, or NGLs from these or any other potential drilling locations.
Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success rate within a particular area may decline. In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or natural gas from all of them.
Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory and delineation drilling in these plays are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling results are unsuccessful.
Many of our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore, and being able to run tools and recover equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools and other equipment the entire length of the well bore during completion operations, being able to recover such tools and other equipment, and successfully cleaning out the well bore after completion of the final fracture stimulation.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for crude oil, natural gas, and NGL decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future.
Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on our investments in such projects.
We inject water into formations on some of our properties to increase the production of crude oil, natural gas, and associated liquids. We may in the future expand these efforts to more of our properties or employ other enhanced recovery methods in our operations. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of crude oil, natural gas, and associated liquids in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. In addition, if proposed legislation and regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery methods could increase substantially.
Our commodity derivative contract activities may result in financial losses or may limit the prices that we receive for crude oil, natural gas, and NGL sales.
To mitigate a portion of the exposure to potentially adverse market changes in crude oil, natural gas, and
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NGL prices and the associated impact on cash flows, the Company has entered into various derivative contracts. The Company’s derivative contracts in place include swap and collar arrangements for crude oil, natural gas, and NGLs. As of December 31, 2011, we were in a net accrued asset position of $31.2 million with respect to our crude oil, natural gas, and NGL derivative activities. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
• | our production is less than expected; |
• | one or more counterparties to our commodity derivative contracts default on their contractual obligations; or |
• | there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement. |
The risk of one or more counterparties defaulting on their obligations is heightened by the recent global and domestic economic and financial downturn affecting many banks and other financial institutions, including our counterparties and their affiliates. These circumstances may adversely affect the ability of our counterparties to meet their obligations to us pursuant to derivative transactions, which could reduce our revenues and cash flows from realized derivative cash settlements. As a result, our financial condition, results of operations, and cash flows could be materially affected in an adverse way if our counterparties default on their contractual obligations under our commodity derivative contracts.
In addition, commodity derivative contracts may limit the prices that we receive for our crude oil, natural gas and NGL sales if crude oil, natural gas, or NGL prices rise substantially over the price established by the commodity derivative contract.
The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from crude oil, natural gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various economic and other conditions, including the recent global and domestic economic and financial downturn.
In addition, for the year ended December 31, 2011, one customer, Regency, individually accounted for approximately 18 percent of our total production revenue. During 2010 and 2009, we had one customer each year, Regency and Teppco Crude Oil LLC, individually account for approximately 11 percent and 12 percent, respectively, of our total production revenue. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices at which we sell such products.
We have entered into firm transportation contracts that require us to pay fixed amounts of money to our counterparties regardless of quantities actually shipped, processed, or gathered. If we are unable to deliver the necessary quantities of natural gas to our counterparties, our results of operations and liquidity could be adversely affected.
As of December 31, 2011, we were contractually committed to deliver 1,766 Bcf of natural gas and 9 MMbl of oil pursuant to contracts expiring at various dates through 2023. We may enter into additional firm transportation agreements as our development of our shale plays, including the Eagle Ford and Haynesville shales, expand. At the current time, we do not have enough proved developed reserves to offset these contractual liabilities, but we intend to develop reserves that will exceed the commitments and therefore do not expect any shortfalls. We expect our production volumes, as well as that of our competitors, to increase significantly in the Eagle Ford shale. The use of firm transportation commitments gives us the strategic advantage of priority space in a transportation pipeline. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptions of
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operations, or delays in connecting new volumes to gathering systems or pipelines for an extended period of time, the requirements to pay for quantities not delivered could have a material impact on our results of operations and liquidity.
Future crude oil, natural gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.
We follow the successful efforts method of accounting for our crude oil and natural gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If commercial quantities of hydrocarbons are not discovered with an exploratory well, the costs of drilling the well are expensed.
The capitalized costs of our crude oil, natural gas, and NGL properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated discounted future net cash flows of that depletion pool. Unproved properties are evaluated at the lower of cost or fair market value. We incurred an impairment of proved property and impairment of unproved properties totaling $219.0 million and $7.4 million, respectively, during 2011, $6.1 million and $2.0 million, respectively, during 2010, and $174.8 million and $45.4 million, respectively, during 2009. Significant further declines in crude oil, natural gas, or NGL prices in the future or unsuccessful exploration efforts could cause further impairment write-downs of capitalized costs.
We review the carrying value of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of each quarter. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date, even if crude oil, natural gas, or NGL prices increase.
Lower crude oil, natural gas, or NGL prices could limit our ability to borrow under our credit facility.
Our credit facility has a current commitment amount of $1.0 billion, subject to a borrowing base that the lenders periodically redetermine based largely on the bank group’s assessment of the value of our crude oil, natural gas, and NGL properties, which in turn is impacted by crude oil, natural gas, and NGL prices. The current borrowing base under our credit facility is $1.3 billion. Declines in crude oil, natural gas, or NGL prices in the future could limit our borrowing base and reduce our ability to borrow under our credit facility. Additionally, divestitures of properties could result in a reduction of our borrowing base.
Our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt.
As of December 31, 2011, we had $285.1 million, net of debt discount, of total long-term senior unsecured debt outstanding under our 3.50% Senior Convertible Notes Due 2027 ("3.50% Senior Convertible Notes"); $350.0 million of long-term senior unsecured debt outstanding relating to our 6.625% Senior Notes that we issued on February 7, 2011; $350.0 million of long-term senior unsecured debt outstanding relating to our 6.50% Senior Notes that we issued on November 8, 2011; and no outstanding borrowings under our secured credit facility (other than two outstanding letters of credit in the aggregate amount of $608,000, which reduce the amount available for borrowings under the facility on a dollar-for-dollar basis), resulting in $999.4 million of available debt capacity under our credit facility, assuming the borrowing conditions of this facility were met. Our long-term debt represented 40 percent of our total book capitalization as of December 31, 2011.
Our indebtedness could have important consequences for our operations, including:
• | making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements; |
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• | requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments; |
• | limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends; |
• | placing us at a competitive disadvantage compared to our competitors that have less debt; and |
• | making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business. |
Our ability to make payments on our debt and to refinance our debt and fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory, and other factors that are beyond our control. If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our credit facility or from other sources, we might not be able to service our debt or fund our other liquidity needs. If we are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity securities, divest assets, or restructure or refinance our debt. We might not be able to sell our equity securities, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our existing and future credit agreements, may prohibit us from pursuing any of these alternatives. Further, changes in the credit ratings of our debt may negatively affect the cost, terms, conditions, and availability of future financing. The indenture under our 3.50% Senior Convertible Notes provides that under certain circumstances we have the option to settle our obligations under these senior convertible notes through the issuance of shares of our common stock if we so elect.
Our debt agreements, including the agreement governing our credit facility and the indentures governing the 6.625% Senior Notes and 6.50% Senior Notes, permit us to incur additional debt in the future, subject to compliance with restrictive covenants under those agreements. In addition, entities we may acquire in the future could have significant amounts of debt outstanding that we could be required to assume, and in some cases accelerate repayment thereof, in connection with the acquisition, or we may incur our own significant indebtedness to consummate an acquisition.
As discussed above, our credit facility is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowing base or arrange new financing, we may be forced to sell significant assets.
The agreements governing our debt contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.
Our debt agreements contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under our credit facility is subject to compliance with certain financial covenants, including (i) maintenance of a quarterly ratio of total debt to consolidated earnings before interest, taxes, depreciation, amortization, and exploration expense of no greater than 4.0 to 1.0, and (ii) maintenance of a current ratio of no less than 1.0 to 1.0, each as defined in our credit facility. Our credit facility also requires us to comply with certain financial covenants, including requirements that we maintain certain levels of stockholders’ equity and limit our annual cash dividends to no more than $50.0 million. These restrictions on our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities.
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The respective indentures governing the 6.625% Senior Notes and the 6.50% Senior Notes also contain covenants that, among other things, limit our ability and the ability of our subsidiaries to:
• | incur additional debt; |
• | make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock; |
• | sell assets, including capital stock of our subsidiaries; |
• | restrict dividends or other payments of our subsidiaries; |
• | create liens that secure debt; |
• | enter into transactions with affiliates; and |
• | merge or consolidate with another company. |
Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.
We are subject to operating and environmental risks and hazards that could result in substantial losses.
Crude oil and natural gas operations are subject to many risks, including human error and accidents that could cause personal injury, death and property damage, well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas and associated liquids or well fluids, fires, adverse weather such as hurricanes in the South Texas & Gulf Coast region, freezing conditions in the Williston Basin of our Rocky Mountain region, floods, droughts, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas such as hydrogen sulfide, and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses.
There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation, handling and disposal of materials, including solid and hazardous wastes and petroleum hydrocarbons. We may incur joint and several, strict liability under applicable United States federal and state environmental laws in connection with releases of petroleum hydrocarbons and other hazardous substances at, on, under or from our leased or owned properties, some of which have been used for natural gas and oil exploration and production activities for a number of years, often by third parties not under our control. For our non-operated properties, we are dependent on the operator for operational and regulatory compliance, and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed thereon or away from could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including the CERCLA or the Superfund law, the RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under any implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damage allegedly caused by the release of petroleum hydrocarbons or other wastes into the environment. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses.
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We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damage or insurance coverage for environmental damage that occurs over time is available at a reasonable cost. In addition, pollution and environmental risks generally are not fully insurable. Further, we may elect not to obtain other insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer a material loss.
Following the severe Atlantic hurricanes in 2004, 2005, and 2008, the insurance markets suffered significant losses. As a result, insurance coverage for wind storms has become substantially more expensive, and future availability and costs of coverage are uncertain.
Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks.
Federal, state, tribal, and local authorities extensively regulate the oil and natural gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing or marketing of crude oil, natural gas and NGL production. Noncompliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages, the imposition of significant investigatory and remedial obligations and may also result in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability.
Governmental authorities regulate various aspects of drilling for and the production of crude oil, natural gas, and NGLs, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in crude oil and natural gas properties, rights-of-way and easements, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, and restoration standards, oil and gas operations, and restoration. Public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Federal authorities also may require any of our ongoing or planned operations on federal leases to be delayed, suspended, or terminated. Any such delay, suspension, or termination could have a materially adverse effect on our operations.
Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, tribal and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability, including joint and several, strict liability under federal, state, and tribal environmental laws for noise emissions and for discharges of crude oil, natural gas, and associated liquids or other pollutants into the air, soil, surface water, or groundwater. We could be required to spend substantial amounts on investigations, litigation, and remediation for these discharges and other compliance issues. Any unpermitted release of petroleum or other pollutants from our operations could result not only in cleanup costs, but also natural resources, real or personal property and other compensatory damages and civil and criminal liability. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect on us.
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Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Operations in certain of our regions, such as our Rocky Mountain and Permian regions, are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. Wildlife seasonal restrictions may limit access to federal leases or across federal lands. Possible restrictions may include seasonal restrictions in greater sage-grouse habitat during breeding and nesting seasons, within a certain distance of active raptor nests during fledging, and in big game winter or parturition ranges during winter or calving seasons. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas and associated liquids from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the Eagle Ford shale of south Texas, and the Bakken/Three Forks formations in North Dakota. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving the use of diesel in the fluid system under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. If hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit or disclosure requirements or operational restrictions and also to associated permitting delays, litigation risk, and potential cost increases.
Certain states that we operate in, including Pennsylvania, Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas ("RCT") and the public of certain information regarding the components and volume of water used in the hydraulic fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells.
There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating a review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the United States Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the United States
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Department of the Interior is developing disclosure requirements or other mandates for hydraulic fracturing on federal lands.
Additionally, certain members of Congress have called upon the United States Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the United States Securities and Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the United States Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their course and outcomes, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory processes.
Further, on July 28, 2011, the EPA issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards ("NSPS") and National Emission Standards for Hazardous Air Pollutants ("NESHAPS") programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion ("REC") techniques developed in EPA's Natural Gas STAR program along with the pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology ("MACT") standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently evaluating the effect these proposed rules could have on our business. Final action on the proposed rules is expected by March or April, 2012.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing such activity to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. Additional legislation or regulation could also lead to operational delays or increased costs in the exploration for and production of oil, natural gas, and associated liquids, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state, or local laws, or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows.
On October 20, 2011, the EPA announced a schedule for development of standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works ("POTWs"). The regulations will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. The EPA anticipates issuing the proposed rules in 2014.
Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.
The hydraulic fracturing process on which we depend to drill for commercial quantities of crude oil, natural gas, and associated liquids requires the use and disposal of significant quantities of water.
Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or
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disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of natural gas.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.
Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.
On September 12, 2011, President Obama sent to Congress a legislative package that included proposed legislation that, if enacted into law, would eliminate certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, among other proposals:
• | the repeal of the percentage depletion allowance for oil and natural gas properties; |
• | the elimination of current deductions for intangible drilling and development costs; |
• | the elimination of the deduction for certain domestic production activities; and |
• | an extension of the amortization period for certain geological and geophysical expenditures. |
These proposals also were included in President Obama's Proposed Fiscal Year 2012 Budget. It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in 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. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.
Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for crude oil, natural gas, and NGLs.
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 a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. For example, the EPA has adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other regulates the permitting and 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 large 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 the courts, several cases are pending that may increase the risk of claims being filed against companies that have significant greenhouse gas emissions. Such cases seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property. Any laws or regulations that restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas that we produce.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce
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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, gas, and NGLs we produce. 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 predicted 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 such effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from flooding or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.
Current or proposed financial legislation and rulemaking 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"), which was signed into law on July 21, 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Commodities Futures Trading Commission (the "CFTC") is required to implement rules relating to these activities by July 16, 2012. On October 18, 2011, the CFTC approved regulations to set position limits for certain futures and option contracts in the major energy markets, which regulations are presently being challenged in federal court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association. The Dodd-Frank Act may also require us to comply with margin requirements and with certain clearing and trade execution requirements in our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.
The Dodd-Frank Act and any new regulations could significantly 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 Dodd-Frank Act 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 Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.
Our ability to sell crude oil, natural gas and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines and other transportation
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systems owned or operated by others or by other interruptions.
The marketability of our crude oil, natural gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, and pipeline and other transportation systems owned or operated by third parties. The lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lower price realizations. Although we have some contractual control over the processing and transportation of our production, material changes in these business relationships could materially affect our operations. Federal and state regulation of crude oil, natural gas, and NGLs production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, and transport crude oil, natural gas, and NGLs.
In particular, if drilling in the Eagle Ford shale, Haynesville shale, Bakken/Three Forks resource play, and Granite Wash resource play continues to be successful, the amount of crude oil, natural gas, and NGLs being produced by us and others could exceed the capacity of, and result in strains on, the various gathering and transportation systems, pipelines, processing facilities, and other infrastructure available in these areas. It will be necessary for additional infrastructure, pipelines, gathering and transportation systems and processing facilities to be expanded, built or developed to accommodate anticipated production from these areas. Because of the current economic climate, certain processing, pipeline, and other gathering or transportation projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing or other constraints. In addition, capital and other constraints could limit our ability to build or access intrastate gathering and transportation systems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient infrastructure development or capacity expansion and/or sell production at significantly lower prices, which would adversely affect our results of operations and cash flows.
A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows and results of operations.
New technologies may cause our current exploration and drilling methods to become obsolete.
The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.
Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions.
As a crude oil, natural gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance
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that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.
Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.
The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for crude oil, natural gas, and NGLs, all of which could adversely affect the markets for our operations. Energy assets might be specific targets of terrorist attacks. These developments have subjected our operations to increased risk and, depending on their occurrence and ultimate magnitude, could have a material adverse effect on our business.
Risks Related to Our Common Stock
The price of our common stock may fluctuate significantly, which may result in losses for investors.
From January 1, 2011, to February 16, 2012, the closing daily sale price of our common stock as reported by the New York Stock Exchange ranged from a low of $56.04 per share in January 2011 to a high of $86.85 per share in October 2011. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:
• | changes in crude oil, natural gas, or NGL prices; |
• | variations in drilling, recompletion, and operating activity; |
• | changes in financial estimates by securities analysts; |
• | changes in market valuations of comparable companies; |
• | additions or departures of key personnel; |
• | future sales of our common stock; and |
• | changes in the national and global economic outlook. |
We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result.
Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment.
Our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.
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Shares eligible for future sale may cause the market price of our common stock to drop significantly, even if our business is doing well.
The potential for sales of substantial amounts of our common stock in the public market may have a materially adverse effect on our stock price. As of February 16, 2012, 64,068,540 shares of our common stock were freely tradable without substantial restriction or the requirement of future registration under the Securities Act of 1933. Also as of that date, options to purchase 458,263 shares of our common stock were outstanding, all of which were exercisable. These options are exercisable at prices ranging from $10.86 to $20.87 per share. In addition, restricted stock units (“RSUs”) providing for the issuance of up to a total of 308,412 shares of our common stock and 1,230,814 performance share units ("PSUs") were outstanding. PSUs are structurally the same as the previously granted Performance Share Awards or ("PSAs") (collectively known as "Performance Share Units" or "PSUs"). The PSUs represent the right to receive, upon settlement of the PSUs after the completion of a three-year performance period, a number of shares of our common stock that may be from zero to two times the number of PSUs granted, depending on the extent to which the underlying performance criteria have been achieved and the extent to which the PSUs have vested. In addition, we may issue additional shares of our common stock in connection with a put or conversion of our 3.50% Senior Convertible Notes. As of February 16, 2012, there were 64,114,366 shares of our common stock outstanding, which is net of 81,067 treasury shares.
We may not always pay dividends on our common stock.
Payment of future dividends remains at the discretion of the Board of Directors, and will continue to depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to a covenant in our credit facility limiting our annual cash dividends to no more than $50.0 million, and to covenants in the indentures for our 6.625% Senior Notes and 6.50% Senior Notes that limit our ability to pay dividends beyond a certain amount. Our Board of Directors may determine in the future to reduce the current semi-annual dividend rate of $0.05 per share, or discontinue the payment of dividends altogether.
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ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Securities Exchange Act of 1934.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the filing date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows.
We note that approximately 22,000 acres of our approximately 196,000 net acres in the Eagle Ford shale play in South Texas are the subject of a lawsuit captioned W.H. Sutton, et al. vs. St. Mary Land & Exploration Co., et al. instituted in the District Court of Webb County in and for the 49th Judicial District of Texas on May 13, 2010. The plaintiffs claim an aggregate overriding royalty interest of 7.46875% in production attributable to a 1966 oil, gas and mineral lease, and that such overriding royalty interest attaches to subsequent leases currently affecting the acreage that is the subject of the lawsuit, which had been released from the 1966 lease. At the original lease date, the 1966 lease was executed for approximately 40,000 acres. The plaintiffs seek to quiet title to their claimed overriding royalty interest and the recovery of unpaid overriding royalty interest proceeds allegedly due. We believe that the claimed overriding royalty interest has been terminated under the governing agreements and the applicable law, and have contested the plaintiffs’ claims. Both parties filed motions for summary judgment, and on February 8, 2011, the District Court issued an order granting plaintiffs’ motion for summary judgment and denying our motion for summary judgment. The order granting plaintiffs’ motion for summary judgment did not award damages but reserved such determination for final order. We believe that the summary judgment is incorrect under the governing agreements and applicable law, and we have appealed the court's ruling. On September 30, 2011, the District Court entered final judgment for the plaintiffs and awarded damages of approximately $5.1 million, which includes prejudgment interest. The District Court also awarded attorneys fees and costs. We have appealed the District Court's judgment and obtained a stay pending appeal that prevents the plaintiffs from executing on the judgment.
We believe this lawsuit is entirely without merit and we will continue to vigorously contest this litigation. However, we cannot predict the ultimate outcome of this lawsuit. If the plaintiffs were to ultimately prevail, the overriding royalty interest would have the effect of reducing our net revenue interest in the affected acreage, which would negatively impact our economics in this portion of our acreage, but we do not believe would have a material adverse effect upon our financial condition, results of operations, or cash flows. For a more detailed discussion of our Eagle Ford shale play, see Core Operational Areas, South Texas & Gulf Coast Region in Part I, Items 1 and 2 of this report.
We recently filed, in Webb County, Texas, a declaratory judgment action, captioned SM Energy Company vs. W.H. Sutton, et al., seeking a judgment declaring that the 1966 lease terminated with respect to the remaining 18,000 acres, based upon a failure of continuous development, and that any overriding royalty interest claimed by the defendants' has been extinguished.
ITEM 4. MINE SAFETY DISCLOSURES
These disclosures are not applicable to us.
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PART II
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Market Information. Our common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM”. The following table presents the range of high and low intraday sales prices per share for the indicated quarterly periods in 2011 and 2010, as reported by the New York Stock Exchange:
Quarter Ended | High | Low | ||||
December 31, 2011 | $ | 88.50 | $ | 53.45 | ||
September 30, 2011 | 85.55 | 60.52 | ||||
June 30, 2011 | 78.55 | 61.37 | ||||
March 31, 2011 | 75.00 | 54.59 | ||||
December 31, 2010 | $ | 59.82 | $ | 37.30 | ||
September 30, 2010 | 44.93 | 33.80 | ||||
June 30, 2010 | 49.13 | 35.29 | ||||
March 31, 2010 | 38.18 | 30.70 | ||||
PERFORMANCE GRAPH
The following performance graph compares the cumulative return on our common stock, for the period beginning December 31, 2006, and ending on December 31, 2011, with the cumulative total returns of the Dow Jones U.S. Exploration and Production Board Index, and the Standard & Poor’s 500 Stock Index.
COMPARE 5-YEAR CUMULATIVE TOTAL RETURN
The preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the Securities and Exchange Commission.
Holders. As of February 16, 2012, the number of record holders of SM Energy's common stock was 90. Based upon inquiry, SM Energy had approximately 35,800 beneficial owners of its common stock in 2011.
Dividends. We have paid cash dividends to our stockholders every year since 1940. Annual dividends of $0.05 per share were paid in each of the years 1998 through 2004. Annual dividends of $0.10 per share were paid in 2005 through 2011. We expect that our practice of paying dividends on our common stock will continue,
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although the payment of future dividends will continue to depend on our earnings, cash flow, capital requirements, financial condition, and other factors, including the discretion of our Board of Directors. In addition, the payment of dividends is subject to covenants in our credit facility that limit our annual dividend payment to no more than $50.0 million per year. We are also subject to certain covenants under our 6.625% Senior Notes and 6.50% Senior Notes that restrict certain payments, including dividends; provided, however, the first $6.5 million of dividends paid each year are not restricted by this covenant. Based on our current performance, we do not anticipate that these covenants will restrict future annual dividend payments of $0.10 per share of common stock. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $6.4 million in 2011 and $6.3 million in 2010.
Restricted Shares. We have no restricted shares outstanding as of December 31, 2011, aside from Rule 144 restrictions on shares held by insiders and shares issued to members of the Board of Directors under our Equity Incentive Compensation Plan (“Equity Plan”).
Purchases of Equity Securities by the Issuer and Affiliated Purchasers. The following table provides information about purchases by the Company and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and year ended December 31, 2011, of shares of the Company’s common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act.
ISSUER PURCHASES OF EQUITY SECURITIES | ||||||||||||
Total Number of Shares Purchased(1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Program | Maximum Number of Shares that May Yet be Purchased Under the Program(2) | |||||||||
January 1, 2011 – March 31, 2011 | 8,878 | $ | 72.47 | — | 3,072,184 | |||||||
April 1, 2011 - June 30, 2011 | — | $ | — | — | 3,072,184 | |||||||
July 1, 2011 - September 30, 2011 | 123,504 | $ | 75.49 | — | 3,072,184 | |||||||
October 1, 2011 - October 31, 2011 | — | $ | — | — | 3,072,184 | |||||||
November 1, 2011 - November 30, 2011 | 88 | $ | 78.92 | — | 3,072,184 | |||||||
December 1, 2011 - December 31, 2011 | — | $ | — | — | 3,072,184 | |||||||
Total October 1, 2011 - December 31, 2011 | 88 | $ | 78.92 | — | 3,072,184 | |||||||
Total | 132,470 | $ | 75.29 | — | 3,072,184 | |||||||
(1) | All shares purchased in 2011 were to offset tax withholding obligations that occur upon the delivery of outstanding shares underlying RSUs and PSUs delivered under the terms of grants under the Equity Plan. |
(2) | In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility, the indentures governing our 6.625% Senior Notes and 6.50% Senior Notes and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued at any time. Please refer to Dividends above for a description of our dividend limitations. |
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ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected supplemental financial and operating data for us as of the dates and periods indicated. The financial data for each of the five years presented were derived from our consolidated financial statements. The following data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report, which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our consolidated financial statements included in this report.
Years Ended December 31, | |||||||||||||||||||
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
(in millions, except per share data) | |||||||||||||||||||
Total operating revenues | $ | 1,603.3 | $ | 1,092.8 | $ | 832.2 | $ | 1,301.3 | $ | 990.1 | |||||||||
Net income (loss) | $ | 215.4 | $ | 196.8 | $ | (99.4 | ) | $ | 87.3 | $ | 187.1 | ||||||||
Net income (loss) per share: | |||||||||||||||||||
Basic | $ | 3.38 | $ | 3.13 | $ | (1.59 | ) | $ | 1.40 | $ | 3.02 | ||||||||
Diluted | $ | 3.19 | $ | 3.04 | $ | (1.59 | ) | $ | 1.38 | $ | 2.90 | ||||||||
Total assets at year-end | $ | 3,799.0 | $ | 2,744.3 | $ | 2,360.9 | $ | 2,697.2 | $ | 2,572.9 | |||||||||
Long-term debt: | |||||||||||||||||||
Line of credit | $ | — | $ | 48.0 | $ | 188.0 | $ | 300.0 | $ | 285.0 | |||||||||
3.50% Senior Convertible Notes, net of debt discount | $ | 285.1 | $ | 275.7 | $ | 266.9 | $ | 258.7 | $ | 251.1 | |||||||||
6.625% Senior Notes | $ | 350.0 | $ | — | $ | — | $ | — | $ | — | |||||||||
6.50% Senior Notes | $ | 350.0 | $ | — | $ | — | $ | — | $ | — | |||||||||
Cash dividends declared and paid per common share | $ | 0.10 | $ | 0.10 | $ | 0.10 | $ | 0.10 | $ | 0.10 | |||||||||
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Supplemental Selected Financial and Operations Data | |||||||||||||||||||
Years Ended December 31, | |||||||||||||||||||
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
Balance Sheet Data (in millions) | |||||||||||||||||||
Total working capital (deficit) | $ | (42.6 | ) | $ | (227.4 | ) | $ | (87.6 | ) | $ | 15.2 | $ | (92.6 | ) | |||||
Total stockholders’ equity | $ | 1,462.9 | $ | 1,218.5 | $ | 973.6 | $ | 1,162.5 | $ | 902.6 | |||||||||
Weighted-average common shares outstanding (in thousands) | |||||||||||||||||||
Basic | 63,755 | 62,969 | 62,457 | 62,243 | 61,852 | ||||||||||||||
Diluted | 67,564 | 64,689 | 62,457 | 63,133 | 64,850 | ||||||||||||||
Reserves | |||||||||||||||||||
Oil (MMBbl) | 71.7 | 57.4 | 53.8 | 51.4 | 78.8 | ||||||||||||||
Gas (Bcf) | 664.0 | 640.0 | 449.5 | 557.4 | 613.5 | ||||||||||||||
NGLs (MMBbl) | 27.5 | — | — | — | — | ||||||||||||||
BCFE | 1,259.2 | 984.5 | 772.2 | 865.5 | 1,086.5 | ||||||||||||||
Production and Operational (in millions) | |||||||||||||||||||
Oil, gas, and NGL production revenues | $ | 1,332.4 | $ | 836.3 | $ | 616.0 | $ | 1,259.4 | $ | 912.1 | |||||||||
Oil, gas, and NGL production expenses | $ | 290.1 | $ | 195.1 | $ | 206.8 | $ | 271.4 | $ | 218.2 | |||||||||
DD&A | $ | 511.1 | $ | 336.1 | $ | 304.2 | $ | 314.3 | $ | 227.6 | |||||||||
General and administrative | $ | 118.5 | $ | 106.7 | $ | 76.0 | $ | 79.5 | $ | 60.1 | |||||||||
Production Volumes | |||||||||||||||||||
Oil (MMBbl) | 8.1 | 6.4 | 6.3 | 6.6 | 6.9 | ||||||||||||||
Gas (Bcf) | 100.3 | 71.9 | 71.1 | 74.9 | 66.1 | ||||||||||||||
NGLs (MMBbl) | 3.5 | — | — | — | — | ||||||||||||||
BCFE | 169.7 | 110.0 | 109.1 | 114.6 | 107.5 | ||||||||||||||
Realized price | |||||||||||||||||||
Oil (per Bbl) | $ | 88.23 | $ | 72.65 | $ | 54.40 | $ | 92.99 | $ | 67.56 | |||||||||
Gas (per Mcf) | $ | 4.32 | $ | 5.21 | $ | 3.82 | $ | 8.60 | $ | 6.74 | |||||||||
NGL (per Bbl) | $ | 53.32 | $ | — | $ | — | $ | — | $ | — | |||||||||
Adjusted price (net of derivative cash settlements) | |||||||||||||||||||
Oil (per Bbl) | $ | 78.89 | $ | 66.85 | $ | 56.74 | $ | 75.59 | $ | 62.60 | |||||||||
Gas (per Mcf) | $ | 4.80 | $ | 6.05 | $ | 5.59 | $ | 8.79 | $ | 7.63 | |||||||||
NGL (per Bbl) | $ | 47.90 | $ | — | $ | — | $ | — | $ | — | |||||||||
Expense per MCFE | |||||||||||||||||||
LOE | $ | 0.88 | $ | 1.10 | $ | 1.33 | $ | 1.46 | $ | 1.31 | |||||||||
Transportation | $ | 0.51 | $ | 0.19 | $ | 0.19 | $ | 0.19 | $ | 0.14 | |||||||||
Production taxes | $ | 0.32 | $ | 0.48 | $ | 0.37 | $ | 0.71 | $ | 0.58 | |||||||||
DD&A | $ | 3.01 | $ | 3.06 | $ | 2.79 | $ | 2.74 | $ | 2.12 | |||||||||
General and administrative | $ | 0.70 | $ | 0.97 | $ | 0.70 | $ | 0.69 | $ | 0.56 | |||||||||
Statement of Cash Flow Data (in millions) | |||||||||||||||||||
Provided by operations | $ | 760.5 | $ | 497.1 | $ | 436.1 | $ | 679.2 | $ | 632.1 | |||||||||
(Used in) investing | $ | (1,264.9 | ) | $ | (361.6 | ) | $ | (304.1 | ) | $ | (673.8 | ) | $ | (805.1 | ) | ||||
Provided by (used in) financing | $ | 618.5 | $ | (141.1 | ) | $ | (127.5 | ) | $ | (42.8 | ) | $ | 215.1 | ||||||
Note: Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. Beginning in the first quarter of 2011, we changed our reporting for natural gas volumes to separately show natural gas and NGL production volumes, revenues, and pricing consistent with title transfer for each product. Please refer to additional discussion above under the caption Oil, Gas, and NGL Prices in Part II, Item 7 of this report.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion includes forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statements in Part I, Items 1 and 2 of this report for important information about these types of statements.
Overview of the Company
General Overview
We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. Our assets include leading positions in the Eagle Ford shale and Bakken/Three Forks resource plays, as well as meaningful positions in the Granite Wash, Haynesville shale, and Woodford shale resource plays. We have built a portfolio of onshore properties in the contiguous United States primarily through early entrance into existing and emerging resource plays. This portfolio is comprised of properties with established production and reserves, prospective drilling opportunities, and unconventional resource prospects. We believe our strategy provides for stable and predictable production and reserve growth. Furthermore, by entering these plays early, we believe that we can capture larger resource potential at a lower cost.
In general, we generate almost all of our revenues and cash flows from the sale of produced oil, gas and NGLs. In 2011, we also generated meaningful gains and cash proceeds from the divestiture of oil and gas properties. Please refer to the discussion below under 2011 Highlights.
Our business strategy is focused on the early capture of resource plays in order to create and then enhance value for our shareholders, while maintaining a strong balance sheet. We strive to leverage industry leading exploration and leasehold acquisition teams to quickly acquire and test new resource play concepts at a reasonable cost. Once we have captured potential value through these efforts, our goal is to develop such potential through top tier operational and project execution, and as appropriate, mitigate our risk in asset development by divesting of all or a portion of certain assets. We continually examine our portfolio for opportunities to improve the quality of our asset base in order to maximize our returns and preserve our financial strength.
In 2011 we had the following financial and operational results:
• | At year-end 2011, we had estimated proved reserves of 1,259.2 BCFE, of which 53 percent was natural gas and 67 percent was characterized as proved developed. We added 526.1 BCFE from our drilling program, the majority of which related to our activity in the Eagle Ford shale in South Texas, the Bakken/Three Forks plays in North Dakota, and the Haynesville Shale in East Texas. We sold 93.1 BCFE of proved reserves during the year related to assets located primarily in our South Texas & Gulf Coast region. We had negative price revisions that decreased our estimated proved reserves by 25.3 BCFE due to lower commodity prices in our gas-weighted regions. The prices used in the calculation of proved reserve estimates as of December 31, 2011, were $96.19 per Bbl, $4.12 per MMBtu, and $59.37 per Bbl, for oil, natural gas, and NGLs, respectively. These prices were 21 percent higher for oil and six percent lower for natural gas than the prices used at year-end 2010. Performance revisions in 2011 resulted in a net 36.8 BCFE increase in our estimate of proved reserves. This increase includes the impact of our conversion to three stream production, which is partially offset by negative engineering revisions due primarily to the failure of Woodford shale wells in our Mid-Continent region to satisfy our internal economic hurdles due to current commodity prices and well costs. |
• | The PV-10 value of our estimated proved reserves was $3.5 billion as of December 31, 2011, compared with $2.3 billion as of December 31, 2010. The after tax value, represented by the standardized measure calculation, was $2.6 billion as of December 31, 2011, compared with $1.7 billion as of |
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December 31, 2010. The standardized measure calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown under Reserves in Part I, Items 1 and 2 of this report.
• | We had record production in 2011. Our average daily production in 2011 was 274.8 MMcf of gas, 22.1 MBbl of oil, and 9.6 MBbl of NGLs, for an average equivalent production rate of 465.0 MMCFE, compared with 301.4 MMCFE in 2010, an increase of 54 percent year over year. |
• | We had record net income of $215.4 million and diluted earnings per share of $3.19 for the year ended December 31, 2011. This compares with net income of $196.8 million, or $3.04 per diluted share, for the year ended December 31, 2010. |
• | We had record cash flow from operating activities of $760.5 million for the year ended December 31, 2011, compared with $497.1 million as of December 31, 2010, which was an increase of 53 percent year over year. |
• | Costs incurred for oil and gas producing activities for the year ended December 31, 2011, were $1.6 billion, compared with $877.4 million for the same period in 2010. |
Reserve Replacement, Finding and Development Costs, and Growth
Like all oil and gas exploration and production companies, we face the challenge of growing proved reserves. An exploration and production company depletes part of its asset base with each unit of oil, gas, or NGL it produces. Our future growth will depend on our ability to organically and economically add reserves in excess of production.
The following table provides various reserve replacement and finding and development cost metrics for the year ended December 31, 2011:
Reserve Replacement Percentage | Finding and Development Cost per MCFE | ||||||||||||
Excluding Divestitures | Including Divestitures | Excluding Divestitures | Including Divestitures | ||||||||||
Drilling, excluding revisions | 310 | % | 255 | % | $ | 2.85 | $ | 3.46 | |||||
Drilling, including revisions | 317 | % | 262 | % | $ | 2.79 | $ | 3.37 | |||||
Drilling and acquisitions, excluding revisions | 310 | % | 255 | % | $ | 2.85 | $ | 3.46 | |||||
Drilling and acquisitions, including revisions | 317 | % | 262 | % | $ | 2.79 | $ | 3.37 | |||||
Reserve Acquisitions* | N/A* | N/A* | N/A* | N/A* | |||||||||
All-in | 317 | % | 262 | % | $ | 2.89 | $ | 3.50 | |||||
*There were no proved reserve acquisitions in 2011. | |||||||||||||
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The following table provides average reserve replacement and finding and development cost metrics for the three-year period ended December 31, 2011:
Reserve Replacement Percentage | Finding and Development Cost per MCFE | ||||||||||||
Excluding Divestitures | Including Divestitures | Excluding Divestitures | Including Divestitures | ||||||||||
Drilling, excluding revisions | 262 | % | 205 | % | $ | 2.65 | $ | 3.39 | |||||
Drilling, including revisions | 259 | % | 201 | % | $ | 2.68 | $ | 3.45 | |||||
Drilling and acquisitions, excluding revisions | 262 | % | 205 | % | $ | 2.65 | $ | 3.39 | |||||
Drilling and acquisitions, including revisions | 259 | % | 201 | % | $ | 2.68 | $ | 3.45 | |||||
Reserve Acquisitions | N/M* | N/M* | $ | 3.36 | N/M* | ||||||||
All-in | 259 | % | 201 | % | $ | 2.83 | $ | 3.64 | |||||
* N/M – Percentage or amount, as applicable, is not meaningful. | |||||||||||||
Our challenge is to grow net asset value per share, which we believe drives appreciation in our stock price over the long term. To accomplish this, we believe it is important to organically and economically replace annual production with new reserves. We believe annual reserve replacement percentage and finding and development costs are important analytical measures that are widely used by investors and industry peers in evaluating and comparing the performance of oil and gas companies. While single-year measurements have some meaning in terms of a trend, we believe that aberrations, causing both good and bad results, will occur over short intervals of time. The information used to calculate the above reserve replacement and finding and development cost metrics is included in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. For additional information about these metrics, see the reserve replacement and finding and development cost terms in the Glossary of Oil and Gas Terms at the end of Part I, Items 1 and 2 of this report.
Oil, Gas, and NGL Prices
Our financial condition and the results of our operations are significantly affected by the prices we receive for oil, gas, and NGL production, which can fluctuate dramatically. Prior to 2011, we reported our natural gas production as a single stream of rich gas measured at the well head. As a result, we reported realized prices for our natural gas production for periods through December 31, 2010, that were higher than industry benchmarks due to the price uplift associated with incremental value contained in the higher BTU content of our produced gas stream. Beginning in the first quarter of 2011, we changed our reporting for natural gas volumes to show natural gas and NGL production volumes consistent with title transfer for each product. Projected rapid production growth from our NGL-rich assets associated with plant product sales contracts necessitated a change in our reporting of production volumes. Prior period production volumes, revenues, and prices have not been reclassified to conform to the current presentation given the immateriality of the NGL volumes produced in prior periods. We sell the majority of our natural gas under contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced. For assets where high BTU gas is sold at the wellhead, we also receive additional value for the high energy content contained in the gas stream. Our NGL production is generally sold using contracts paying us a monthly average of the posted OPIS Mont Belvieu daily settlement prices, adjusted for processing, transportation, and location differentials. Our crude oil and condensate are sold using contracts paying us either the average of the NYMEX WTI daily settlement price or the average of alternative posted prices for the periods in which the product is produced, adjusted for quality, transportation, and location differentials.
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The following table is a summary of commodity price data for the years ended December 31, 2011, 2010, and 2009.
For the Years Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
Crude Oil (per Bbl): | |||||||||||
Average NYMEX price | $ | 95.05 | $ | 79.51 | $ | 61.99 | |||||
Realized price | $ | 88.23 | $ | 72.65 | $ | 54.40 | |||||
Natural Gas (per Mcf): | |||||||||||
Average NYMEX price | $ | 4.00 | $ | 4.37 | $ | 3.94 | |||||
Realized price | $ | 4.32 | $ | 5.21 | $ | 3.82 | |||||
NGLs (per Bbl): | |||||||||||
Average OPIS price | $ | 59.47 | |||||||||