UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
T QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2016
or
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to _________
Commission File Number 001-37419
PDC ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware | 95-2636730 |
(State of incorporation) | (I.R.S. Employer Identification No.) |
1775 Sherman Street, Suite 3000
Denver, Colorado 80203
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (303) 860-5800
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. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer x | 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 x
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 46,318,394 shares of the Company's Common Stock ($0.01 par value) were outstanding as of April 18, 2016.
PDC ENERGY, INC.
TABLE OF CONTENTS
PART I – FINANCIAL INFORMATION | Page | ||
Item 1. | Financial Statements | ||
Item 2. | |||
Item 3. | |||
Item 4. | |||
PART II – OTHER INFORMATION | |||
Item 1. | |||
Item 1A. | |||
Item 2. | |||
Item 3. | |||
Item 4. | |||
Item 5. | |||
Item 6. | |||
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: estimated future production (including the components of such production), sales, expenses, cash flows, liquidity and balance sheet attributes; estimated crude oil, natural gas and natural gas liquids (“NGLs”) reserves; the impact of prolonged depressed commodity prices including potentially reduced production and associated cash flow; anticipated capital projects, expenditures and opportunities, including our expectation that 2016 cash flows from operations will approximate cash flows from investing activities; expected capital budget allocations; our operational flexibility and ability to revise our development plan, either upward or downward; availability of sufficient funding and liquidity for our capital program and sources of that funding; that we do not expect a material change in the borrowing base of our revolving credit facility as a result of the May 2016 semi-annual redetermination; that we expect quarter-over-quarter production growth; expected losses of Riley Natural Gas ("RNG") through 2022 and expected discontinuation of RNG's business; future exploration, drilling and development activities, including non-operated activity, the number of drilling rigs we expect to run, number of locations and lateral lengths; expected 2016 production and cash flow ranges; our evaluation method of our customers' and derivative counterparties' credit risk; effectiveness of our derivative program in providing a degree of price stability; potential for future impairments; expected sustained relief of gathering system pressure; compliance with debt and senior notes covenants; expected funding sources for payment of our 3.25% convertible senior notes due May 2016; impact of litigation on our results of operations and financial position; that we do not expect to pay dividends in the foreseeable future; and our future strategies, plans and objectives.
The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the terms “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.
Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
• | changes in worldwide production volumes and demand, including economic conditions that might impact demand; |
• | volatility of commodity prices for crude oil, natural gas and NGLs and the risk of an extended period of depressed prices; |
• | reductions in the borrowing base under our revolving credit facility; |
• | impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations; |
• | declines in the value of our crude oil, natural gas and NGLs properties resulting in further impairments; |
• | changes in estimates of proved reserves; |
• | inaccuracy of reserve estimates and expected production rates; |
• | potential for production decline rates from our wells being greater than expected; |
• | timing and extent of our success in discovering, acquiring, developing and producing reserves; |
• | availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production; |
• | timing and receipt of necessary regulatory permits; |
• | risks incidental to the drilling and operation of crude oil and natural gas wells; |
• | future cash flows, liquidity and financial condition; |
• | competition within the oil and gas industry; |
• | availability and cost of capital; |
• | our success in marketing crude oil, natural gas and NGLs; |
• | effect of crude oil and natural gas derivatives activities; |
• | impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events; |
• | cost of pending or future litigation; |
• | effect that acquisitions we may pursue have on our capital expenditures; |
• | our ability to retain or attract senior management and key technical employees; and |
• | success of strategic plans, expectations and objectives for our future operations. |
Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2015 (the "2015 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 22, 2016, and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which
are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.
REFERENCES
Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships. See Note 1, Nature of Operations and Basis of Presentation, to our condensed consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries.
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PDC ENERGY, INC.
Condensed Consolidated Balance Sheets
(unaudited; in thousands, except share and per share data)
March 31, 2016 | December 31, 2015 | |||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 238,545 | $ | 850 | ||||
Accounts receivable, net | 100,053 | 104,274 | ||||||
Fair value of derivatives | 183,484 | 221,659 | ||||||
Prepaid expenses and other current assets | 5,970 | 5,266 | ||||||
Total current assets | 528,052 | 332,049 | ||||||
Properties and equipment, net | 1,942,498 | 1,940,552 | ||||||
Fair value of derivatives | 35,641 | 44,387 | ||||||
Other assets | 9,206 | 53,555 | ||||||
Total Assets | $ | 2,515,397 | $ | 2,370,543 | ||||
Liabilities and Shareholders' Equity | ||||||||
Liabilities | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 73,898 | $ | 92,613 | ||||
Production tax liability | 26,541 | 26,524 | ||||||
Fair value of derivatives | 5,173 | 1,595 | ||||||
Funds held for distribution | 28,008 | 29,894 | ||||||
Current portion of long-term debt | 114,183 | 112,940 | ||||||
Accrued interest payable | 19,758 | 9,057 | ||||||
Other accrued expenses | 20,610 | 28,709 | ||||||
Total current liabilities | 288,171 | 301,332 | ||||||
Long-term debt | 492,717 | 529,437 | ||||||
Deferred income taxes | 100,080 | 143,452 | ||||||
Asset retirement obligation | 82,703 | 84,032 | ||||||
Fair value of derivatives | 5,966 | 695 | ||||||
Other liabilities | 29,311 | 24,398 | ||||||
Total liabilities | 998,948 | 1,083,346 | ||||||
Commitments and contingent liabilities | ||||||||
Shareholders' equity | ||||||||
Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued | — | — | ||||||
Common shares - par value $0.01 per share, 150,000,000 authorized, 46,210,022 and 40,174,776 issued as of March 31, 2016 and December 31, 2015, respectively | 462 | 402 | ||||||
Additional paid-in capital | 1,208,117 | 907,382 | ||||||
Retained earnings | 308,892 | 380,422 | ||||||
Treasury shares - at cost, 20,836 and 20,220 as of March 31, 2016 and December 31, 2015, respectively | (1,022 | ) | (1,009 | ) | ||||
Total shareholders' equity | 1,516,449 | 1,287,197 | ||||||
Total Liabilities and Shareholders' Equity | $ | 2,515,397 | $ | 2,370,543 | ||||
See accompanying Notes to Condensed Consolidated Financial Statements
1
PDC ENERGY, INC.
Condensed Consolidated Statements of Operations
(unaudited; in thousands, except per share data)
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
Revenues | ||||||||
Crude oil, natural gas and NGLs sales | $ | 75,367 | $ | 74,109 | ||||
Sales from natural gas marketing | 2,171 | 3,233 | ||||||
Commodity price risk management gain, net | 11,056 | 66,662 | ||||||
Well operations, pipeline income and other | 2,237 | 628 | ||||||
Total revenues | 90,831 | 144,632 | ||||||
Costs, expenses and other | ||||||||
Lease operating expenses | 15,330 | 16,285 | ||||||
Production taxes | 4,071 | 3,893 | ||||||
Transportation, gathering and processing expenses | 4,041 | 1,338 | ||||||
Cost of natural gas marketing | 2,578 | 3,258 | ||||||
Exploration expense | 210 | 285 | ||||||
Impairment of crude oil and natural gas properties | 1,001 | 2,772 | ||||||
General and administrative expense | 22,779 | 21,045 | ||||||
Depreciation, depletion and amortization | 97,388 | 55,820 | ||||||
Provision for uncollectible notes receivable | 44,738 | — | ||||||
Accretion of asset retirement obligations | 1,812 | 1,560 | ||||||
Gain on sale of properties and equipment | (84 | ) | (21 | ) | ||||
Total cost, expenses and other | 193,864 | 106,235 | ||||||
Income (loss) from operations | (103,033 | ) | 38,397 | |||||
Interest expense | (11,894 | ) | (11,725 | ) | ||||
Interest income | 1,558 | 1,113 | ||||||
Income (loss) from before income taxes | (113,369 | ) | 27,785 | |||||
Provision for income taxes | 41,839 | (10,723 | ) | |||||
Net income (loss) | $ | (71,530 | ) | $ | 17,062 | |||
Earnings per share: | ||||||||
Basic | $ | (1.72 | ) | $ | 0.47 | |||
Diluted | $ | (1.72 | ) | $ | 0.46 | |||
Weighted-average common shares outstanding: | ||||||||
Basic | 41,608 | 36,349 | ||||||
Diluted | 41,608 | 36,981 | ||||||
See accompanying Notes to Condensed Consolidated Financial Statements
2
PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited; in thousands)
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | $ | (71,530 | ) | $ | 17,062 | |||
Adjustments to net income (loss) to reconcile to net cash from operating activities: | ||||||||
Net change in fair value of unsettled derivatives | 55,770 | (16,230 | ) | |||||
Depreciation, depletion and amortization | 97,388 | 55,820 | ||||||
Provision for uncollectible notes receivable | 44,738 | — | ||||||
Impairment of crude oil and natural gas properties | 1,001 | 2,772 | ||||||
Accretion of asset retirement obligation | 1,812 | 1,560 | ||||||
Stock-based compensation | 4,682 | 4,368 | ||||||
Gain on sale of properties and equipment | (84 | ) | (21 | ) | ||||
Amortization of debt discount and issuance costs | 1,754 | 1,751 | ||||||
Deferred income taxes | (43,372 | ) | 8,534 | |||||
Non-cash interest income | (1,194 | ) | (1,112 | ) | ||||
Other | (8 | ) | (568 | ) | ||||
Changes in assets and liabilities | 10,193 | 7,941 | ||||||
Net cash from operating activities | 101,150 | 81,877 | ||||||
Cash flows from investing activities: | ||||||||
Capital expenditures | (122,759 | ) | (176,111 | ) | ||||
Proceeds from sale of properties and equipment | 90 | 24 | ||||||
Net cash from investing activities | (122,669 | ) | (176,087 | ) | ||||
Cash flows from financing activities: | ||||||||
Proceeds from sale of common stock, net of issuance costs | 296,578 | 202,851 | ||||||
Proceeds from revolving credit facility | 85,000 | 165,000 | ||||||
Repayment of revolving credit facility | (122,000 | ) | (221,000 | ) | ||||
Other | (364 | ) | (1,213 | ) | ||||
Net cash from financing activities | 259,214 | 145,638 | ||||||
Net change in cash and cash equivalents | 237,695 | 51,428 | ||||||
Cash and cash equivalents, beginning of period | 850 | 16,066 | ||||||
Cash and cash equivalents, end of period | $ | 238,545 | $ | 67,494 | ||||
Supplemental cash flow information: | ||||||||
Cash payments for: | ||||||||
Interest, net of capitalized interest | $ | 599 | $ | 569 | ||||
Income taxes | — | 8,088 | ||||||
Non-cash investing and financing activities: | ||||||||
Change in accounts payable related to purchases of properties and equipment | $ | (23,544 | ) | $ | (35,836 | ) | ||
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals | 404 | 302 | ||||||
Purchase of properties and equipment under capital leases | 635 | 472 | ||||||
See accompanying Notes to Condensed Consolidated Financial Statements
3
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2015
(Unaudited)
NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION
PDC Energy, Inc. (the "Company," "we," "us," or "our") is a domestic independent exploration and production company that produces, develops, acquires and explores for crude oil, natural gas and NGLs, with primary operations in the Wattenberg Field in Colorado and the Utica Shale in southeastern Ohio. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Ohio operations are focused in the Utica Shale play. As of March 31, 2016, we owned an interest in approximately 3,000 gross wells. We are engaged in two business segments: Oil and Gas Exploration and Production and Gas Marketing.
The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiary Riley Natural Gas ("RNG") and our proportionate share of our four affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.
In our opinion, the accompanying condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2015 condensed consolidated balance sheet data was derived from audited statements, but does not include disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2015 Form 10-K. Our results of operations and cash flows for the three months ended March 31, 2016 are not necessarily indicative of the results to be expected for the full year or any other future period.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when (or as) each performance obligation is satisfied. In March 2016, the FASB issued an update to the standard intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations when recognizing revenue. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.
In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard requires management to assess an entity's ability to continue as a going concern at the end of every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. We expect to adopt this standard in the fourth quarter of 2016. Adoption of this standard is not expected to have a significant impact on our condensed consolidated financial statements.
In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. For leases with terms of more than twelve months, the accounting update requires lessees to recognize an asset for its right to use the underlying asset and a lease liability for the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.
In March 2016, the FASB issued an accounting update on stock-based compensation intended to simplify several aspects of the accounting for employee share-based payment award transactions. Areas of simplification include income tax consequences, classification of the awards as either equity or liabilities and the classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.
4
NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS
Derivative Financial Instruments
Determination of Fair Value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:
Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.
Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.
We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.
Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our collars and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:
March 31, 2016 | December 31, 2015 | ||||||||||||||||||||||
Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
Assets: | |||||||||||||||||||||||
Commodity-based derivative contracts | $ | 144,968 | $ | 74,109 | $ | 219,077 | $ | 174,657 | $ | 91,288 | $ | 265,945 | |||||||||||
Basis protection derivative contracts | 48 | — | 48 | 101 | — | 101 | |||||||||||||||||
Total assets | 145,016 | 74,109 | 219,125 | 174,758 | 91,288 | 266,046 | |||||||||||||||||
Liabilities: | |||||||||||||||||||||||
Commodity-based derivative contracts | 8,733 | 1,004 | 9,737 | 738 | — | 738 | |||||||||||||||||
Basis protection derivative contracts | 1,402 | — | 1,402 | 1,552 | — | 1,552 | |||||||||||||||||
Total liabilities | 10,135 | 1,004 | 11,139 | 2,290 | — | 2,290 | |||||||||||||||||
Net asset | $ | 134,881 | $ | 73,105 | $ | 207,986 | $ | 172,468 | $ | 91,288 | $ | 263,756 | |||||||||||
5
The following table presents a reconciliation of our Level 3 assets measured at fair value:
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
(in thousands) | ||||||||
Fair value, net asset beginning of period | $ | 91,288 | $ | 62,356 | ||||
Changes in fair value included in statement of operations line item: | ||||||||
Commodity price risk management gain (loss), net | 6,165 | 15,189 | ||||||
Sales from natural gas marketing | (20 | ) | 1 | |||||
Settlements included in statement of operations line items: | ||||||||
Commodity price risk management gain (loss), net | (24,258 | ) | (2,725 | ) | ||||
Sales from natural gas marketing | (70 | ) | (4 | ) | ||||
Fair value, net asset end of period | $ | 73,105 | $ | 74,817 | ||||
Net change in fair value of unsettled derivatives included in statement of operations line item: | ||||||||
Commodity price risk management gain (loss), net | $ | 4,185 | $ | 14,494 | ||||
Sales from natural gas marketing | — | — | ||||||
Total | $ | 4,185 | $ | 14,494 | ||||
The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts.
Non-Derivative Financial Assets and Liabilities
The carrying value of the financial instruments included in current assets and current liabilities, excluding the current portion of long-term debt, approximate fair value due to the short-term maturities of these instruments.
We utilize fair value on a nonrecurring basis to review our crude oil and natural gas properties for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold.
The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. The liability related to this plan, which was included in other liabilities on the condensed consolidated balance sheets, was immaterial as of March 31, 2016 and December 31, 2015.
The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, as of March 31, 2016, we estimate the fair value of the portion of our long-term debt related to our 3.25% convertible senior notes due 2016 to be $152.0 million, or 132.2% of par value, and the portion related to our 7.75% senior notes due 2022 to be $497.6 million, or 99.5% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs.
The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the vehicle lease.
Concentration of Risk
Derivative Counterparties. Our derivative arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no counterparty default losses relating to our derivative arrangements. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments was not significant at March 31, 2016, taking into account the estimated likelihood of nonperformance.
6
The following table presents the counterparties that expose us to credit risk as of March 31, 2016 with regard to our derivative assets:
Counterparty Name | Fair Value of Derivative Assets | |||
(in thousands) | ||||
Canadian Imperial Bank of Commerce (1) | $ | 63,503 | ||
JP Morgan Chase Bank, N.A (1) | 56,261 | |||
Bank of Nova Scotia (1) | 41,254 | |||
Wells Fargo Bank, N.A. (1) | 29,029 | |||
NATIXIS (1) | 24,159 | |||
Other lenders in our revolving credit facility | 4,919 | |||
Total | $ | 219,125 | ||
__________
(1)Major lender in our revolving credit facility. See Note 7, Long-Term Debt.
Notes Receivable. The following table presents information regarding our note receivable outstanding as of March 31, 2016:
Amount | |||
(in thousands) | |||
Note receivable: | |||
Principal outstanding, December 31, 2015 | $ | 43,069 | |
Paid-in-kind interest | 969 | ||
Principal outstanding, March 31, 2016 | 44,038 | ||
Allowance for uncollectible notes receivable | (44,038 | ) | |
Note receivable, net | $ | — | |
In October 2014, we sold our entire 50% ownership interest in PDCM to an unrelated third-party. As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39.0 million, bearing interest at varying rates beginning at 8%, and increasing annually. Pursuant to the Note agreement, interest is payable quarterly, in arrears, commencing in December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. As of March 31, 2016, the issuer of the Note had elected the PIK Interest option. The principal and any unpaid interest is due and payable in full in September 2020 and can be prepaid in whole or in part at any time without premium or penalty. In events of default as defined by the Note agreement, the Note must be repaid prior to maturity. As of March 31, 2016, we have been notified that no event of default has occurred and is continuing. The Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets.
On a quarterly basis, we examine the Note for evidence of impairment, evaluating factors such as the creditworthiness of the issuer of the Note and the value of the underlying assets that secure the Note. We performed our quarterly evaluation and cash flow analysis and, based upon the unaudited year-end financial statements and reserve report of the issuer of the Note received by us in late March 2016 and current market conditions, determined that collection of the Note and PIK Interest was not reasonably assured. As a result, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.0 million outstanding balance as of March 31, 2016, which was included in the condensed consolidated balance sheet line item other assets.
Additionally, we recorded a $0.7 million provision and allowance for uncollectible notes receivable to impair a promissory note related to a previous divestiture as collection of the promissory note is not reasonably assured based on the analysis we performed as of March 31, 2016.
Under the effective interest method, we recognized $1.2 million and $1.1 million of interest income for the three months ended March 31, 2016 and 2015, respectively, of which $1.0 million and $0.8 million, respectively, was PIK Interest.
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NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS
Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas, we utilize the following economic hedging strategies for each of our business segments.
• | For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and |
• | For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. |
We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of March 31, 2016, we had derivative instruments, which were comprised of collars, fixed-price swaps, basis protection swaps and physical sales and purchases, in place for a portion of our anticipated production through 2018 for a total of 75,680 BBtu of natural gas and 9,067 MBbls of crude oil. The majority of our derivative contracts are entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices.
We have not elected to designate any of our derivative instruments as hedges, and therefore do not qualify for use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing.
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The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets:
Fair Value | |||||||||||
Derivative instruments: | Balance sheet line item | March 31, 2016 | December 31, 2015 | ||||||||
(in thousands) | |||||||||||
Derivative assets: | Current | ||||||||||
Commodity contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | $ | 183,240 | $ | 221,161 | ||||||
Related to natural gas marketing | Fair value of derivatives | 276 | 441 | ||||||||
Basis protection contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | (32 | ) | 57 | |||||||
183,484 | 221,659 | ||||||||||
Non-current | |||||||||||
Commodity contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 35,542 | 44,292 | ||||||||
Related to natural gas marketing | Fair value of derivatives | 19 | 51 | ||||||||
Basis protection contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 80 | 44 | ||||||||
35,641 | 44,387 | ||||||||||
Total derivative assets | $ | 219,125 | $ | 266,046 | |||||||
Derivative liabilities: | Current | ||||||||||
Commodity contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | $ | 3,622 | $ | — | ||||||
Related to natural gas marketing | Fair value of derivatives | 249 | 417 | ||||||||
Basis protection contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 1,302 | 1,178 | ||||||||
5,173 | 1,595 | ||||||||||
Non-current | |||||||||||
Commodity contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 5,854 | 275 | ||||||||
Related to natural gas marketing | Fair value of derivatives | 12 | 46 | ||||||||
Basis protection contracts | |||||||||||
Related to crude oil and natural gas sales | Fair value of derivatives | 100 | 374 | ||||||||
5,966 | 695 | ||||||||||
Total derivative liabilities | $ | 11,139 | $ | 2,290 | |||||||
The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:
Three Months Ended March 31, | ||||||||
Condensed consolidated statement of operations line item | 2016 | 2015 | ||||||
(in thousands) | ||||||||
Commodity price risk management gain, net | ||||||||
Net settlements | $ | 66,831 | $ | 50,412 | ||||
Net change in fair value of unsettled derivatives | (55,775 | ) | 16,250 | |||||
Total commodity price risk management gain, net | $ | 11,056 | $ | 66,662 | ||||
Sales from natural gas marketing | ||||||||
Net settlements | $ | 245 | $ | 232 | ||||
Net change in fair value of unsettled derivatives | (220 | ) | (170 | ) | ||||
Total sales from natural gas marketing | $ | 25 | $ | 62 | ||||
Cost of natural gas marketing | ||||||||
Net settlements | $ | (228 | ) | $ | (218 | ) | ||
Net change in fair value of unsettled derivatives | 225 | 150 | ||||||
Total cost of natural gas marketing | $ | (3 | ) | $ | (68 | ) | ||
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All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets.
The following table reflects the impact of netting agreements on gross derivative assets and liabilities:
As of March 31, 2016 | Derivative instruments, recorded in condensed consolidated balance sheet, gross | Effect of master netting agreements | Derivative instruments, net | |||||||||
(in thousands) | ||||||||||||
Asset derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 219,125 | $ | (10,215 | ) | $ | 208,910 | |||||
Liability derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 11,139 | $ | (10,215 | ) | $ | 924 | |||||
As of December 31, 2015 | Derivative instruments, recorded in condensed consolidated balance sheet, gross | Effect of master netting agreements | Derivative instruments, net | |||||||||
(in thousands) | ||||||||||||
Asset derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 266,046 | $ | (1,921 | ) | $ | 264,125 | |||||
Liability derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 2,290 | $ | (1,921 | ) | $ | 369 | |||||
NOTE 5 - PROPERTIES AND EQUIPMENT
The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization ("DD&A"):
March 31, 2016 | December 31, 2015 | ||||||
(in thousands) | |||||||
Properties and equipment, net: | |||||||
Crude oil and natural gas properties | |||||||
Proved | $ | 2,954,843 | $ | 2,881,189 | |||
Unproved | 60,806 | 60,498 | |||||
Total crude oil and natural gas properties | 3,015,649 | 2,941,687 | |||||
Equipment and other | 31,222 | 30,098 | |||||
Land and buildings | 12,111 | 9,015 | |||||
Construction in progress | 135,396 | 113,115 | |||||
Properties and equipment, at cost | 3,194,378 | 3,093,915 | |||||
Accumulated DD&A | (1,251,880 | ) | (1,156,237 | ) | |||
Properties and equipment, net | $ | 1,942,498 | $ | 1,937,678 | |||
The following table presents impairment charges recorded for crude oil and natural gas properties:
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Impairment of proved properties | $ | 969 | $ | 293 | |||
Amortization of individually insignificant unproved properties | 32 | 2,479 | |||||
Impairment of crude oil and natural gas properties | $ | 1,001 | $ | 2,772 | |||
NOTE 6 - INCOME TAXES
We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. A tax expense or benefit unrelated to the current year income or loss is recognized in its entirety as a discrete item of tax in the period identified. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.
The effective tax rate for the three months ended March 31, 2016 was a 36.9% benefit on loss compared to a 38.6% provision on income for the three months ended March 31, 2015. The effective tax rate for the three months ended March 31, 2016 is based upon a full year forecasted tax benefit on loss and is greater than the statutory federal tax rate, primarily due to state taxes and percentage depletion, partially offset by nondeductible officers’ compensation and nondeductible lobbying expenses. The effective tax rate for the three months ended March 31, 2015 differs from the statutory rate primarily due to state taxes and nondeductible officers' compensation, partially offset by percentage depletion and domestic production deduction. There were no significant discrete items recorded during the three months ended March 31, 2016 or March 31, 2015.
As of March 31, 2016, our liability for unrecognized tax benefits was immaterial. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. We continue voluntary participation in the Internal Revenue Service’s ("IRS") Compliance Assurance Program for the 2015 and 2016 tax years. We have received a partial acceptance notice from the IRS for our filed 2014 federal tax return with one issue still in review.
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NOTE 7 - LONG-TERM DEBT
Long-term debt consists of the following:
March 31, 2016 | December 31, 2015 | ||||||
(in thousands) | |||||||
Senior notes: | |||||||
3.25% Convertible senior notes due 2016: | |||||||
Principal amount | $ | 115,000 | $ | 115,000 | |||
Unamortized discount | (747 | ) | (1,852 | ) | |||
Unamortized debt issuance costs | (70 | ) | (208 | ) | |||
3.25% Convertible senior notes due 2016, net of discount and unamortized debt issuance costs | 114,183 | 112,940 | |||||
7.75% Senior notes due 2022: | |||||||
Principal amount | 500,000 | 500,000 | |||||
Unamortized debt issuance costs | (7,283 | ) | (7,563 | ) | |||
7.75% Senior notes due 2022, net of unamortized debt issuance costs | 492,717 | 492,437 | |||||
Total senior notes | 606,900 | 605,377 | |||||
Revolving credit facility | — | 37,000 | |||||
Total debt, net of discount and unamortized debt issuance costs | 606,900 | 642,377 | |||||
Less current portion of long-term debt | 114,183 | 112,940 | |||||
Long-term debt | $ | 492,717 | $ | 529,437 | |||
Senior Notes
3.25% Convertible Senior Notes Due 2016. In November 2010, we issued $115 million aggregate principal amount 3.25% convertible senior notes due 2016 (the "Convertible Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is May 15, 2016. Interest is payable semi-annually in arrears on each May 15 and November 15. The indenture governing the Convertible Notes contains certain non-financial covenants. We allocated the gross proceeds of the Convertible Notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based upon the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued the Convertible Notes. The original issue discount and capitalized debt issuance costs are being amortized to interest expense over the life of the Convertible Notes using an effective interest rate of 7.4%. As the stated maturity for payment of principal is May 2016, we have included the carrying value of the Convertible Notes, net of discount and unamortized debt issuance costs, in the current portion of long-term debt on our condensed consolidated balance sheet as of March 31, 2016.
Beginning on November 15, 2015, holders of the Convertible Notes became able to convert the notes at an initial conversion rate of 23.5849 shares per $1,000 principal amount, which is equal to a conversion price of approximately $42.40 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, we have elected to settle the principal amount of the Convertible Notes in cash and settle the excess conversion value in shares, as well as cash in lieu of fractional shares. The “if-converted” value of the Convertible Notes as of March 31, 2016 exceeded the aggregate principal amount by approximately $46.2 million.
7.75% Senior Notes Due 2022. In October 2012, we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”) in a private placement to qualified institutional buyers. The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15. The indenture governing the 2022 Senior Notes contains customary restrictive incurrence covenants. Capitalized debt issuance costs are being amortized as interest expense over the life of the 2022 Senior Notes using the effective interest method.
As of March 31, 2016, we were in compliance with all covenants related to the Convertible Notes and the 2022 Senior Notes and expect to remain in compliance throughout the next 12-month period.
Credit Facility
Revolving Credit Facility. We are party to a Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent, and other lenders party thereto (sometimes referred to as the "revolving credit facility"). The revolving credit facility matures in May 2020. The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base. In September 2015, we completed the semi-annual redetermination of our revolving credit facility by the lenders, which resulted in the reaffirmation of our borrowing base at $700 million; however, we have elected to maintain the aggregate commitment at
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$450 million. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of mortgages of certain producing crude oil and natural gas properties. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility.
We had no outstanding balance on our revolving credit facility as of March 31, 2016, compared to $37.0 million outstanding as of December 31, 2015. The weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.6% per annum as of December 31, 2015.
As of March 31, 2016, RNG had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit currently expires in September 2016 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal to the letter of credit. As of March 31, 2016, the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $438.3 million. In addition to our currently elected commitment of $450 million, we have an additional $250 million of borrowing base availability under the revolving credit facility, subject to certain terms and conditions of the agreement.
The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00. As of March 31, 2016, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period.
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NOTE 8 - CAPITAL LEASES
Beginning in the first quarter of 2015, we entered into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. Each lease agreement has a term of three years and is being accounted for as a capital lease, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90% of the fair value of the leased vehicles at inception of the lease.
The following table presents leased vehicles under capital leases as of March 31, 2016:
Amount | ||||
(in thousands) | ||||
Vehicles | $ | 2,236 | ||
Accumulated depreciation | (320 | ) | ||
$ | 1,916 | |||
Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following:
For the Twelve Months Ending March 31, | Amount | |||
(in thousands) | ||||
2017 | $ | 686 | ||
2018 | 823 | |||
2019 | 782 | |||
2,291 | ||||
Less executory cost | (94 | ) | ||
Less amount representing interest | (276 | ) | ||
Present value of minimum lease payments | $ | 1,921 | ||
Short-term capital lease obligations | $ | 501 | ||
Long-term capital lease obligations | 1,420 | |||
$ | 1,921 | |||
Short-term capital lease obligations are included in other accrued expenses on the condensed consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the condensed consolidated balance sheets.
NOTE 9 - ASSET RETIREMENT OBLIGATIONS
The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties:
Amount | |||
(in thousands) | |||
Balance at beginning of period, January 1, 2016 | $ | 89,492 | |
Obligations incurred with development activities | 404 | ||
Accretion expense | 1,812 | ||
Obligations discharged with asset retirements | (2,105 | ) | |
Balance end of period, March 31, 2016 | 89,603 | ||
Less current portion | (6,900 | ) | |
Long-term portion | $ | 82,703 | |
Our estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging and abandonment cost considering federal and state regulatory requirements in effect. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2015, the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 7.6% to 8.0%. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the
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original estimate of undiscounted cash flows or changes in inflation factors and changes to our credit-adjusted risk-free rate as market conditions warrant. Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales and processing agreements on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. As natural gas prices continue to remain depressed, certain third-party producers under our Gas Marketing segment have begun and continue to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. As of March 31, 2016, we have recorded an allowance for doubtful accounts of approximately $0.7 million. We have initiated several legal actions for breach of contract, collection, and related claims against certain third-party producers that are delinquent in their payment obligations, which have to date resulted in one default judgment. There have been no collections received to date and and some of the third-party producers have shut-in their wells.
The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity:
For the Twelve Months Ending March 31, | ||||||||||||||||||||||||||
Area | 2017 | 2018 | 2019 | 2020 | 2021 and Through Expiration | Total | Expiration Date | |||||||||||||||||||
Natural gas (MMcf) | ||||||||||||||||||||||||||
Gas Marketing segment | 7,117 | 7,117 | 7,117 | 7,136 | 16,912 | 45,399 | August 31, 2022 | |||||||||||||||||||
Utica Shale | 2,738 | 2,738 | 2,738 | 2,745 | 9,126 | 20,085 | July 22, 2023 | |||||||||||||||||||
Total | 9,855 | 9,855 | 9,855 | 9,881 | 26,038 | 65,484 | ||||||||||||||||||||
Crude oil (MBbls) | ||||||||||||||||||||||||||
Wattenberg Field | 2,413 | 2,413 | 2,413 | 2,420 | 603 | 10,262 | June 30, 2020 | |||||||||||||||||||
Dollar commitment (in thousands) | $ | 17,573 | $ | 16,847 | $ | 16,324 | $ | 16,369 | $ | 13,122 | $ | 80,235 | ||||||||||||||
Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.
Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of March 31, 2016 and December 31, 2015, we had accrued environmental liabilities in the amount of $4.6 million and $4.1 million, respectively, included in other accrued expenses on the condensed consolidated balance sheets. We are not aware of any environmental claims existing as of March 31, 2016 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown past non-compliance with environmental laws will not be discovered on our properties.
In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the United States Environmental Protection Agency ("EPA"). The Information Request seeks, among other things, information related to the design, operation, and maintenance of our production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focuses on historical operation and design information for 46 of our production facilities and asks that we conduct sampling and analyses at the identified 46 facilities. We responded to the Information Request in January 2016 and have received no response as of the date of this report. We cannot predict the outcome of this matter at this time.
In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. § 25-7-115(2) from the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing and handling operations to minimize leakage to the maximum extent possible of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. We are in the process of responding to the advisory, which has overlap with the Information Request, but cannot predict the outcome of this matter at this time.
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Employment Agreements with Executive Officers. Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company.
NOTE 11 - COMMON STOCK
Sale of Equity Securities
In March 2016, we completed a public offering of 5,922,500 shares of our common stock, par value $0.01 per share, at a price to us of $50.11 per share. Net proceeds of the offering were $296.6 million, after deducting offering expenses and underwriting discounts, of which $59,225 is included in common shares-par value and $296.5 million is included in additional paid-in capital ("APIC") on the March 31, 2016 condensed consolidated balance sheet. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in March 2015.
In March 2015, we completed a public offering of 4,002,000 shares of our common stock, par value $0.01 per share, at a price to us of $50.73 per share. Net proceeds of the offering were $202.9 million, after deducting offering expenses and underwriting discounts, of which $40,020 is included in common shares-par value and $202.8 million is included in APIC on the condensed consolidated balance sheets. The shares were issued pursuant to the effective shelf registration statement on Form S-3 filed with the SEC in March 2015.
Stock-Based Compensation Plans
The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented:
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
(in thousands) | ||||||||
Stock-based compensation expense | $ | 4,682 | $ | 4,368 | ||||
Income tax benefit | (1,782 | ) | (1,659 | ) | ||||
Net stock-based compensation expense | $ | 2,900 | $ | 2,709 | ||||
Stock Appreciation Rights ("SARs")
The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance.
In January 2016, the Compensation Committee awarded 58,709 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Expected term of award | 6.0 years | 5.2 years | |||||
Risk-free interest rate | 1.8 | % | 1.4 | % | |||
Expected volatility | 54.5 | % | 58.0 | % | |||
Weighted-average grant date fair value per share | $ | 26.96 | $ | 22.23 | |||
The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future.
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The following table presents the changes in our SARs for all periods presented:
Three Months Ended March 31, | |||||||||||||||||||||||||||
2016 | 2015 | ||||||||||||||||||||||||||
Number of SARs | Weighted-Average Exercise Price | Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) | Number of SARs | Weighted-Average Exercise Price | Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) | ||||||||||||||||||||
Outstanding beginning of year, January 1, | 326,453 | $ | 38.99 | 279,011 | $ | 38.77 | |||||||||||||||||||||
Awarded | 58,709 | 51.63 | 68,274 | 39.63 | |||||||||||||||||||||||
Exercised | (8,414 | ) | 43.38 | — | $ | 114 | — | — | — | — | |||||||||||||||||
Outstanding at March 31, | 376,748 | 40.86 | 7.4 | $ | 7,002 | 347,285 | 38.94 | 8.0 | $ | 5,245 | |||||||||||||||||
Vested and expected to vest at March 31, | 368,662 | 40.71 | 7.4 | 6,909 | 338,570 | 38.86 | 8.0 | 5,138 | |||||||||||||||||||
Exercisable at March 31, | 243,103 | 37.44 | 6.6 | 5,350 | 191,149 | 35.68 | 7.1 | 3,509 | |||||||||||||||||||
Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our condensed consolidated statement of operations as of March 31, 2016 was $2.7 million. The cost is expected to be recognized over a weighted-average period of 2.0 years.
Restricted Stock Awards
Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed.
In January 2016, the Compensation Committee awarded to our executive officers a total of 61,634 time-based restricted shares that vest ratably over a three-year period ending in January 2019.
The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the three months ended March 31, 2016:
Shares | Weighted-Average Grant-Date Fair Value | |||||
Non-vested at December 31, 2015 | 525,081 | $ | 50.23 | |||
Granted | 85,007 | 51.74 | ||||
Vested | (60,272 | ) | 39.04 | |||
Non-vested at March 31, 2016 | 549,816 | 51.69 | ||||
The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:
As of/for the Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
(in thousands, except per share data) | |||||||
Total intrinsic value of time-based awards vested | $ | 3,072 | $ | 3,682 | |||
Total intrinsic value of time-based awards non-vested | 32,687 | 31,762 | |||||
Market price per common share as of March 31, | 59.45 | 54.04 | |||||
Weighted-average grant date fair value per share | 51.74 | 39.73 | |||||
Total compensation cost related to non-vested time-based awards, net of estimated forfeitures, and not yet recognized in our condensed consolidated statements of operations as of March 31, 2016 was $17.2 million. This cost is expected to be recognized over a weighted-average period of 1.8 years.
Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the
16
market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
In January 2016, the Compensation Committee awarded a total of 24,280 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2018 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions:
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Expected term of award | 3 years | 3 years | |||||
Risk-free interest rate | 1.2 | % | 0.9 | % | |||
Expected volatility | 52.3 | % | 53.0 | % | |||
Weighted-average grant date fair value per share | $ | 72.54 | $ | 57.35 | |||
The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility.
The following table presents the change in non-vested market-based awards during the three months ended March 31, 2016:
Shares | Weighted-Average Grant-Date Fair Value per Share | ||||||
Non-vested at December 31, 2015 | 71,549 | $ | 63.60 | ||||
Granted | 24,280 | 72.54 | |||||
Non-vested at March 31, 2016 | 95,829 | 65.86 | |||||
The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:
As of/for the Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
(in thousands, except per share data) | |||||||
Total intrinsic value of market-based awards non-vested | $ | 5,697 | $ | 6,113 | |||
Market price per common share as of March 31, | 59.45 | 54.04 | |||||
Weighted-average grant date fair value per share | 72.54 | 57.35 | |||||
Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our condensed consolidated statements of operations as of March 31, 2016 was $3.0 million. This cost is expected to be recognized over a weighted-average period of 2.0 years.
NOTE 12 - EARNINGS PER SHARE
Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, Convertible Notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.
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The following table presents a reconciliation of the weighted-average diluted shares outstanding:
Three Months Ended March 31, | |||||
2016 | 2015 | ||||
(in thousands) | |||||
Weighted-average common shares outstanding - basic | 41,608 | 36,349 | |||
Dilutive effect of: | |||||
Restricted stock | — | 226 | |||
Convertible notes | — | 339 | |||
Other equity-based awards | — | 67 | |||
Weighted-average common shares and equivalents outstanding - diluted | 41,608 | 36,981 | |||
We reported a net loss for the three months ended March 31, 2016. As a result, our basic and diluted weighted-average common shares outstanding were the same because the effect of the common share equivalents was anti-dilutive.
The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect:
Three Months Ended March 31, | |||||
2016 | 2015 | ||||
(in thousands) | |||||
Weighted-average common share equivalents excluded from diluted earnings | |||||
per share due to their anti-dilutive effect: | |||||
Restricted stock | 723 | 51 | |||
Convertible notes | 508 | — | |||
Other equity-based awards | 100 | 11 | |||
Total anti-dilutive common share equivalents | 1,331 | 62 | |||
In November 2010, we issued our Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The Convertible Notes could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the three months ended March 31, 2016 as the effect would be anti-dilutive to our earnings per share. Shares issuable upon conversion of the Convertible Notes were included in the diluted earnings per share calculation for the three months ended March 31, 2015, as the average market price during the period exceeded the conversion price. The maturity for the payment of principal of the Convertible Notes is May 15, 2016. Upon maturity, we have elected to settle the principal amount of the Convertible Notes in cash and settle the excess conversion value in shares, as well as cash in lieu of fractional shares.
NOTE 13 - BUSINESS SEGMENTS
We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated.
Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas and NGLs. Segment revenue includes crude oil, natural gas and NGLs sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of crude oil and natural gas properties, direct general and administrative expense and depreciation, depletion and amortization expense.
Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by unrelated third-parties. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income, less costs of natural gas marketing and direct general and administrative expense.
Unallocated Amounts. Unallocated income includes unallocated other revenue, less corporate general and administrative expense, corporate DD&A expense, interest income and interest expense. Unallocated assets include assets utilized for corporate general and administrative purposes, as well as assets not specifically included in our two business segments.
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The following tables present our segment information:
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Segment revenues: | |||||||
Oil and gas exploration and production | $ | 88,660 | $ | 141,399 | |||
Gas marketing | 2,171 | 3,233 | |||||
Total revenues | $ | 90,831 | $ | 144,632 | |||
Segment income (loss) before income taxes: | |||||||
Oil and gas exploration and production | $ | (34,033 | ) | $ | 60,526 | ||
Gas marketing | (407 | ) | (25 | ) | |||
Unallocated | (78,929 | ) | (32,716 | ) | |||
Income (loss) before income taxes | $ | (113,369 | ) | $ | 27,785 | ||
March 31, 2016 | December 31, 2015 | ||||||
(in thousands) | |||||||
Segment assets: | |||||||
Oil and gas exploration and production | $ | 2,482,677 | $ | 2,294,288 | |||
Gas marketing | 4,164 | 4,217 | |||||
Unallocated | 28,556 | 72,038 | |||||
Total assets | $ | 2,515,397 | $ | 2,370,543 | |||
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PDC ENERGY, INC.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements.
EXECUTIVE SUMMARY
Financial Overview
Production volumes increased substantially to 4.6 MMboe for the three months ended March 31, 2016 compared to 2.9 MMboe for the three months ended March 31, 2015, representing an increase of 58%. The increase in production volumes was primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field. Crude oil production increased 46% in the three months ended March 31, 2016, while NGL production increased 76%. Crude oil production comprised approximately 42% of total production in the three months ended March 31, 2016. Natural gas production increased 64% in the three months ended March 31, 2016 compared to the three months ended March 31, 2015, as we shifted our focus from the outer core area to the higher rate of return drilling projects located in the higher gas to oil ratio inner and middle core areas of the Wattenberg Field. Additionally, our middle core wells have shown stronger gas production than anticipated. While production increased during the three months ended March 31, 2016 when compared to the same prior year period, as expected, production decreased when compared to the fourth quarter of 2015 as a majority of wells turned-in-line in the fourth quarter of 2015 occurred closer to the beginning of the quarter while a majority of wells turned-in-line during the three months ended March 31, 2016 occurred toward the end of the quarter. The wells turned-in-line in March 2016 are expected to result in production growth for the second quarter of 2016 as compared to the first quarter of 2016. For the month ended March 31, 2016, our average production rate was 51 MBoe per day, up from 30 MBoe per day for the month ended March 31, 2015.
Crude oil, natural gas and NGLs sales, coupled with the impact of settlement of derivatives, increased during the three months ended March 31, 2016 relative to the same prior year period. Crude oil, natural gas and NGLs sales increased to $75.4 million during the three months ended March 31, 2016 compared to $74.1 million in the same prior year period, due to a 58% increase in production, offset in part by a 36% decrease in the realized price per barrel of crude oil equivalent ("Boe"). The realized price per Boe was $16.49 for the three months ended March 31, 2016 compared to $25.60 for the same prior year period. Positive net settlements on derivatives increased to $66.8 million during the three months ended March 31, 2016 compared to positive net settlements on derivatives of $50.4 million in the same prior year period, due to lower crude oil and natural gas index settlement prices. As a result of these increases, crude oil, natural gas and NGLs sales and the impact of net settlements on derivatives totaled $142.2 million during the three months ended March 31, 2016 compared to $124.5 million during the three months ended March 31, 2015. This represents an increase of 14% compared to the same prior year period. The realized price per Boe, including the impact of net settlements on derivatives, was $31.12 for the three months ended March 31, 2016 compared to $43.01 for the same prior year period.
Additional significant changes impacting our results of operations for the three months ended March 31, 2016 include the following:
• | Negative net change in the fair value of unsettled derivative positions during the three months ended March 31, 2016 was $55.7 million compared to a positive net change in the fair value of unsettled derivative positions of $16.3 million during the same prior year period. The decrease in fair value of unsettled derivative positions was primarily attributable to a higher beginning-of-period fair value of derivatives instruments that settled during the three months ended March 31, 2016 and an upward shift in the crude oil forward curve that occurred during the current quarter; |
• | Depreciation, depletion and amortization expense increased to $97.4 million during the three months ended March 31, 2016 compared to $55.8 million in the same prior year period, primarily due to increased production and, to a lesser extent, a higher weighted-average depreciation, depletion and amortization rate; and |
• | During the quarter ended March 31, 2016, we determined that collection of two third-party notes receivable arising from the sale of our interest in properties in the Marcellus Shale was not reasonably assured based upon current market conditions and new information made available to us. As a result, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.7 million outstanding balance as of March 31, 2016. See Note 3, Fair Value of Financial Instruments - Notes Receivable, to our condensed consolidated financial statements included elsewhere in this report for additional information. |
In March 2016, we completed a public offering of 5,922,500 shares of our common stock at a price to us of $50.11 per share. Net proceeds of the offering were $296.6 million, after deducting offering expenses and underwriting discounts. We used a portion of the net proceeds of the offering to repay all amounts then outstanding on our revolving credit facility and intend to use the remaining amounts to repay the principal amounts owed upon the maturity of the Convertible Notes in May 2016 and for general corporate purposes. With our current derivative position, available liquidity and expected cash flows from operations, we believe we have sufficient liquidity to allow us to fund our operations and execute our expected 2016 capital program.
Available liquidity as of March 31, 2016 was $676.8 million compared to $402.2 million as of December 31, 2015. Available liquidity as of March 31, 2016 is comprised of $238.5 million of cash and cash equivalents and $438.3 million available for borrowing under our revolving credit facility. These amounts exclude an additional $250 million available under our revolving credit facility, subject to certain terms and conditions of the agreement. In September 2015, we completed the semi-annual redetermination of our revolving credit facility by the lenders,
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PDC ENERGY, INC.
which resulted in the reaffirmation of the borrowing base at $700 million. We have elected to maintain the aggregate commitment level at $450 million. We do not currently expect a material change in the borrowing base as a result of the upcoming May 2016 semi-annual redetermination.
Operational Overview
Drilling Activities. During the three months ended March 31, 2016, we continued to execute our strategic plan to grow production while preserving our financial strength and liquidity by managing our capital spending to approximate our cash flows from operations. We are currently running four automated drilling rigs in the Wattenberg Field. During the three months ended March 31, 2016, we spud 41 horizontal wells and turned-in-line 47 horizontal wells in the Wattenberg Field. We also participated in nine gross, 2.5 net, horizontal non-operated wells that were spud and five gross, 1.5 net, horizontal non-operated wells which were turned-in-line. In the Utica Shale, five horizontal wells that were top-hole spud during the fourth quarter of 2015 were in-process as of March 31, 2016. We plan to complete and turn-in-line these wells over the next several months.
2016 Operational Outlook
We expect our production for 2016 to range between 20.0 MMBoe to 22.0 MMBoe and that our production rate will average approximately 55,000 to 60,000 Boe per day. Our 2016 capital forecast of approximately $425 million at the midpoint is focused on continuing to provide value-driven production growth by exploiting our substantial inventory of reasonable rate-of-return projects in the Wattenberg Field.
Wattenberg Field. The 2016 capital forecast anticipates a four-rig drilling program in the Wattenberg Field. Approximately $390 million of our 2016 capital forecast is expected to be spent on development activities in the Wattenberg Field, comprised of approximately $350 million for our operated drilling program and approximately $35 million for non-operated projects. The remainder of the Wattenberg Field capital forecast is expected to be used for leasing, workover projects and other capital improvements, including improvements and expansion of our Greeley, Colorado, field office. We plan to spud 135 and turn-in-line 160 horizontal Niobrara or Codell wells and participate in approximately 35.0 gross, 7.0 net, non-operated horizontal opportunities in 2016. During the three months ended March 31, 2016, we invested approximately $90 million, or approximately 23%, of our 2016 capital forecast for the Wattenberg Field.
Utica Shale. Based on the production results from recently drilled wells and decreases in well costs, in 2016 we plan on executing a modest drilling operation in the condensate and wet natural gas window of the play. In 2016, we plan to spend approximately $35 million in the Utica Shale to drill, complete and turn-in-line five wells, four of which are approximately 6,000 foot laterals. The planned activity will focus on further delineation of our southern acreage, determining the impact of well-orientation on productivity and testing improved capital efficiency of a 10,000 foot lateral well. During the three months ended March 31, 2016, we invested approximately $8 million, or approximately 24%, of our 2016 capital forecast for the Utica Shale to spud five horizontal wells, which we plan to complete and turn-in-line over the next several months.
2016 Operational Flexibility
In December 2015, the Board of Directors approved our 2016 development plan as described above. This plan, which primarily focuses on the four-rig drilling program in the Wattenberg Field, was based upon our goal to preserve our balance sheet by managing our capital spending to approximate our cash flows from operations.
Since approving our 2016 development plan in December 2015, future commodity prices have been volatile. Concurrently, capital costs to drill and complete Wattenberg Field wells have decreased, while crude oil differentials in the field have improved. We expect that our capital forecast of $410 million to $440 million will fund this development plan.
We maintain significant operational flexibility in 2016 to reduce the pace of our capital spending. We will continue to monitor future commodity prices throughout 2016, and should prices remain depressed or continue to further deteriorate, we believe an adjustment to our development plan may be appropriate. We believe we have ample opportunities to reduce capital spending, including but not limited to: working with our vendors to achieve further cost reductions; reducing the number of rigs being utilized in our drilling program; and/or managing our completion schedule. The production impact of reduced 2016 capital spending would be felt primarily in 2017 and thereafter, as our anticipated long-term production growth would likely be reduced. This operational flexibility is maintained with little exposure to incurring additional costs, given that all of our acreage in the Wattenberg Field is held by production, a reduction in rigs would not cause us to incur substantial idling costs as our rig commitments are short term (30 to 90 days), and we do not anticipate having additional material unfulfilled transportation commitment fees.
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PDC ENERGY, INC.
Results of Operations
Summary Operating Results
The following table presents selected information regarding our operating results:
Three Months Ended March 31, | ||||||||||
2016 | 2015 | Percentage Change | ||||||||
(dollars in millions, except per unit data) | ||||||||||
Production (1) | ||||||||||
Crude oil (MBbls) | 1,907.8 | 1,306.7 | 46.0 | % | ||||||
Natural gas (MMcf) | 10,678.0 | 6,524.4 | 63.7 | % | ||||||
NGLs (MBbls) | 882.2 | 500.5 | 76.3 | % | ||||||
Crude oil equivalent (MBoe) (2) | 4,569.7 | 2,894.6 | 57.9 | % | ||||||
Average MBoe per day | 50.2 | 32.2 | 56.1 | % | ||||||
Crude Oil, Natural Gas and NGLs Sales | ||||||||||
Crude oil | $ | 54.0 | $ | 52.0 | 3.8 | % | ||||
Natural gas | 14.9 | 15.8 | (5.7 | )% | ||||||
NGLs | 6.5 | 6.3 | 3.2 | % | ||||||
Total crude oil, natural gas and NGLs sales | $ | 75.4 | $ | 74.1 | 1.8 | % | ||||
Net Settlements on Derivatives (3) | ||||||||||
Natural gas | $ | 13.5 | $ | 5.7 | 136.8 | % | ||||
Crude oil | 53.3 | 44.7 | 19.2 | % | ||||||
Total net settlements on derivatives | $ | 66.8 | $ | 50.4 | 32.5 | % | ||||
Average Sales Price (excluding net settlements on derivatives) | ||||||||||
Crude oil (per Bbl) | $ | 28.29 | $ | 39.82 | (29.0 | )% | ||||
Natural gas (per Mcf) | 1.39 | 2.42 | (42.6 | )% | ||||||
NGLs (per Bbl) | 7.37 | 12.61 | (41.6 | )% | ||||||
Crude oil equivalent (per Boe) | 16.49 | 25.60 | (35.6 | )% | ||||||
Average Lease Operating Expenses (per Boe) (4) | ||||||||||
Wattenberg Field | $ | 3.40 | $ | 6.00 | (43.3 | )% | ||||
Utica Shale | 2.50 | 1.92 | 30.2 | % | ||||||
Weighted-average | 3.35 | 5.63 | (40.5 | )% | ||||||
Natural Gas Marketing Contribution Margin (5) | $ | (0.4 | ) | $ | — | * | ||||
Other Costs and Expenses | ||||||||||
Production taxes | $ | 4.1 | $ | 3.9 | 4.6 | % | ||||
Transportation, gathering and processing expenses | 4.0 | 1.3 | 202.0 | % | ||||||
Impairment of crude oil and natural gas properties | 1.0 | 2.8 | (63.9 | )% | ||||||
General and administrative expense | 22.8 | 21.0 | 8.2 | % | ||||||
Depreciation, depletion and amortization | 97.4 | 55.8 | 74.5 | % | ||||||
Provision for uncollectible notes receivable | 44.7 | — | * | |||||||
Interest expense | $ | 11.9 | $ | 11.7 | 1.4 | % | ||||
* | Percentage change is not meaningful or equal to or greater than 300%. |
Amounts may not recalculate due to rounding.
______________
(1) | Production is net and determined by multiplying the gross production volume of properties in which we have an interest by our ownership percentage. |
(2) | One Bbl of crude oil or NGL equals six Mcf of natural gas. |
(3) | Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to natural gas marketing. |
(4) | Represents lease operating expenses, exclusive of production taxes, on a per unit basis. |
(5) | Represents sales from natural gas marketing, net of costs of natural gas marketing, including net settlements and net change in fair value of unsettled derivatives related to natural gas marketing activities. |
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PDC ENERGY, INC.
Crude Oil, Natural Gas and NGLs Sales
The following tables present crude oil, natural gas and NGLs production and weighted-average sales price:
Three Months Ended March 31, | |||||||||
Production by Operating Region | 2016 | 2015 | Percentage Change | ||||||
Crude oil (MBbls) | |||||||||
Wattenberg Field | 1,818.2 | 1,191.2 | 52.6 | % | |||||
Utica Shale | 89.6 | 115.5 | (22.4 | )% | |||||
Total | 1,907.8 | 1,306.7 | 46.0 | % | |||||
Natural gas (MMcf) | |||||||||
Wattenberg Field | 10,170.4 | 5,911.3 | 72.1 | % | |||||
Utica Shale | 507.6 | 613.1 | (17.2 | )% | |||||
Total | 10,678.0 | 6,524.4 | 63.7 | % | |||||
NGLs (MBbls) | |||||||||
Wattenberg Field | 840.1 | 451.9 | 85.9 | % | |||||
Utica Shale | 42.1 | 48.6 | (13.4 | )% | |||||
Total | 882.2 | 500.5 | 76.3 | % | |||||
Crude oil equivalent (MBoe) | |||||||||
Wattenberg Field | 4,353.4 | 2,628.3 | 65.6 | % | |||||
Utica Shale | 216.3 | 266.3 | (18.8 | )% | |||||
Total | 4,569.7 | 2,894.6 | 57.9 | % | |||||
Amounts may not recalculate due to rounding.
Three Months Ended March 31, | |||||||||||
Average Sales Price by Operating Region | Percentage Change | ||||||||||
(excluding net settlements on derivatives) | 2016 | 2015 | |||||||||
Crude oil (per Bbl) | |||||||||||
Wattenberg Field | $ | 28.37 | $ | 39.93 | (29.0 | )% | |||||
Utica Shale | 26.69 | 38.65 | (30.9 | )% | |||||||
Weighted-average price | 28.29 | 39.82 | (29.0 | )% | |||||||
Natural gas (per Mcf) | |||||||||||
Wattenberg Field | $ | 1.39 | $ | 2.42 | (42.6 | )% | |||||
Utica Shale | 1.43 | 2.39 | (40.2 | )% | |||||||
Weighted-average price | 1.39 | 2.42 | (42.6 | )% | |||||||
NGLs (per Bbl) | |||||||||||
Wattenberg Field | $ | 7.18 | $ | 11.93 | (39.8 | )% | |||||
Utica Shale | 11.24 | 18.95 | (40.7 | )% | |||||||
Weighted-average price | 7.37 | 12.61 | (41.6 | )% | |||||||
Crude oil equivalent (per Boe) | |||||||||||
Wattenberg Field | $ | 16.49 | $ | 25.59 | (35.6 | )% | |||||
Utica Shale | 16.60 | 25.72 | (35.5 | )% | |||||||
Weighted-average price | 16.49 | 25.60 | (35.6 | )% | |||||||
Amounts may not recalculate due to rounding.
For the three months ended March 31, 2016, crude oil, natural gas and NGLs sales revenue increased compared to the three months ended March 31, 2015 due to the following (in millions):
Increase in production | $ | 38.8 | |
Decrease in average crude oil price | (22.0 | ) | |
Decrease in average natural gas price | (10.9 | ) | |
Decrease in average NGLs price | (4.6 | ) | |
Total increase in crude oil, natural gas and NGLs sales revenue | $ | 1.3 | |
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PDC ENERGY, INC.
Production for the first quarter of 2016 was 4.6 million Boe, up from 2.9 million Boe in the first quarter of 2015. Production increased as a result of continued drilling and completion activities as discussed in Operational Overview. We continued to experience lower line pressures in the first quarter of 2016 after our primary service provider, DCP Midstream, completed both its Lucerne 2 plant in June 2015 and its Grand Parkway gas gathering project in December 2015. As a result of the reductions in line pressures, production from our Wattenberg Field legacy vertical wells increased by approximately 152 MBoe, or 36%, during the first quarter of 2016 when compared to the first quarter of 2015. Further, we expect sustained relief of gathering system pressure on our primary gatherer's system through 2016, based upon current and projected drilling activity in the field. However, our secondary midstream service provider, which currently gathers and processes approximately 31% of our Wattenberg Field gas, has indicated it will have limitations on its capital program in 2016, which may result in a curtailment of certain of our projected 2016 volumes. We rely on our third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with our production growth. As a result, the timing and availability of additional facilities going forward is beyond our control. Falling commodity prices have resulted in reduced investment in midstream facilities by some third parties, increasing the risk that sufficient midstream infrastructure will not be available in future periods.
Crude Oil, Natural Gas and NGLs Pricing. Our results of operations depend upon many factors, particularly the price of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices are among the most volatile of all commodity prices. The price of crude oil decreased during the first quarter of 2016 compared to the first half of 2015 amid continuing concerns regarding high U.S. inventories and worldwide production levels that exceed current global demand for crude oil. Natural gas prices decreased during the first quarter of 2016 when compared to the same prior year period. Due to an oversupply of nearly all domestic NGLs products, our realized sales price for NGLs have remained at the low levels seen during the last quarter of 2015 and we expect pricing to remain at depressed levels well into 2016 and perhaps beyond.
Crude oil pricing is predominately driven by the physical market, supply and demand, financial markets and national and international politics. In the Wattenberg Field, crude oil is sold under various purchase contracts with monthly and longer term pricing provisions based on NYMEX pricing, adjusted for differentials. We have entered into longer term commitments ranging from three months to one year to deliver crude oil to competitive markets and these agreements have resulted in significantly improved deductions compared to early 2015. We continue to pursue various alternatives with respect to oil transportation, particularly in the Wattenberg Field, with a view toward further improving pricing and limiting our use of trucking of production. We began delivering crude oil in accordance with our long term commitment to the White Cliffs Pipeline, LLC ("White Cliffs") pipeline in July 2015. This is one of several agreements we have entered into to facilitate deliveries of a portion of our crude oil to the Cushing, Oklahoma market. In addition, we have signed a long-term agreement for gathering of crude oil at the wellhead by pipeline from several of our pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability and reducing the overall physical footprint of our well pads. We began delivering crude oil into this pipeline during the fourth quarter of 2015 and the system was fully operational on certain wells in the first quarter of 2016. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on NYMEX pricing, adjusted for differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities or barge loading terminals on the Ohio River.
Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The price we receive for our natural gas produced in the Wattenberg Field is based on CIG and local utility prices, adjusted for certain deductions, while natural gas produced in the Utica Shale is based on TETCO M-2 pricing. We anticipate that the significant Appalachian pipeline differentials that impact our Utica Shale natural gas will continue through 2016.
Our price for NGLs produced in the Wattenberg Field is based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. The NGLs produced in the Utica Shale are sold based on month-to-month pricing to various markets. Due to an oversupply and growing inventories of nearly all domestic NGLs products, our realized sales price for NGLs declined significantly during the first three quarters of 2015 and, while these prices have stabilized, we expect pricing to remain at depressed levels well into 2016 and perhaps beyond.
Our crude oil, natural gas and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the "net-back" method of accounting for natural gas and NGLs, as well as the majority of our crude oil production, from the Wattenberg Field and for crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation, gathering and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. We use the "gross" method of accounting for Wattenberg Field crude oil delivered through the White Cliffs and Saddle Butte pipelines and for natural gas and NGLs sales related to production from the Utica Shale as the purchasers do not provide transportation, gathering or processing services. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. As a result of the White Cliffs and Saddle Butte agreements, during the three months ended March 31, 2016, our Wattenberg Field crude oil average sales price increased approximately $1.61 per barrel because we recognized the costs for transportation on the White Cliffs and Saddle Butte pipelines as an increase in transportation expense, rather than a deduction from revenues.
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Lease Operating Expenses
The $1.0 million decrease in lease operating expenses during the three months ended March 31, 2016 compared to the three months ended March 31, 2015 was primarily due to a decrease of $1.9 million in environmental remediation and regulatory compliance projects, offset in part by an increase of $0.3 million in workover materials and $0.4 million in water hauling and leased generators.
Production Taxes
Production taxes are directly related to crude oil, natural gas and NGLs sales. The $0.2 million, or 5%, increase in production taxes for the three months ended March 31, 2016 compared to the three months ended March 31, 2015, was primarily related to the 2% increase in crude oil, natural gas and NGLs sales and higher production tax rates.
Transportation, Gathering and Processing Expenses
The $2.7 million increase during the three months ended March 31, 2016 compared to the three months ended March 31, 2015 was mainly attributable to oil transportation cost on the White Cliffs and Saddle Butte pipelines as we began delivering crude oil on these pipelines in July 2015 and December 2015, respectively. We expect to continue to incur these oil transportation costs pursuant to our long-term firm transportation agreement.
Commodity Price Risk Management, Net
We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our natural gas and crude oil production at prices similar to the indexes inherent in our derivative instruments, adjusted for certain fees and surcharges stipulated in the applicable sales agreements, we ultimately realize a price, before contract fees, related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps, less deductions. See Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for a detailed presentation of our derivative positions as of March 31, 2016.
Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments and the change in fair value of unsettled derivatives related to our crude oil and natural gas production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for additional details of our derivative financial instruments.
Net settlements are primarily the result of crude oil and natural gas index prices at maturity of our derivative instruments compared to the respective strike prices. Net change in fair value of unsettled derivatives is comprised of the net asset increase or decrease in the beginning-of-period fair value of derivative instruments that settled during the period and the net change in fair value of unsettled derivatives during the period. The corresponding impact of settlement of the derivative instruments that settled during the period is included in net settlements for the period as discussed above. Net change in fair value of unsettled derivatives during the period is primarily related to shifts in the crude oil and natural gas forward curves and changes in certain differentials. See Note 4, Derivative Financial Instruments, to our consolidated financial statements included elsewhere in this report for a detailed description of net settlements on our various derivatives.
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The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net:
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
(in millions) | |||||||
Commodity price risk management gain, net: | |||||||
Net settlements: | |||||||
Crude oil | $ | 53.3 | $ | 44.7 | |||
Natural gas | 13.5 | 5.7 | |||||
Total net settlements | 66.8 | 50.4 | |||||
Change in fair value of unsettled derivatives: | |||||||
Reclassification of settlements included in prior period changes in fair value of derivatives | (58.9 | ) | (43.9 | ) | |||
Crude oil fixed price swaps | (5.4 | ) | 29.6 | ||||
Crude oil collars | 1.2 | 9.0 | |||||
Natural gas fixed price swaps | 5.8 | 15.2 | |||||
Natural gas basis swaps | (0.4 | ) | 0.6 | ||||
Natural gas collars | 2.0 | 5.8 | |||||
Net change in fair value of unsettled derivatives | (55.7 | ) | 16.3 | ||||
Total commodity price risk management gain, net | $ | 11.1 | $ | 66.7 | |||
Impairment of Crude Oil and Natural Gas Properties
The following table sets forth the major components of our impairment of crude oil and natural gas properties expense:
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
(in millions) | |||||||
Impairment of proved properties | $ | 0.9 | $ | 0.3 | |||
Amortization of individually insignificant unproved properties | 0.1 | 2.5 | |||||
Total impairment of crude oil and natural gas properties | $ | 1.0 | $ | 2.8 | |||
Impairment of proved and unproved properties. Amounts represent the write-down of certain capitalized well costs on our Wattenberg Field properties as the expected development date for these locations are beyond the limits of the SEC five-year rule. Further deterioration of commodity prices could result in additional impairment charges to our crude oil and natural gas properties.
Amortization of individually insignificant unproved properties. Amounts relate to insignificant leases that were subject to amortization, primarily in the Utica Shale where we have altered drilling plans due to lower crude oil prices and, as a result, expect certain leases to expire. The carrying value of our Utica Shale leases decreased significantly due to an impairment in the third quarter of 2015, resulting in lower amortization during the three months ended March 31, 2016 compared to the three months ended March 31, 2015.
General and Administrative Expense
General and administrative expense increased $1.7 million to $22.8 million for the three months ended March 31, 2016 compared to $21.0 million for the three months ended March 31, 2015. The increase was primarily attributable to a $0.6 million increase in payroll and employee benefits, a $0.6 million increase in costs for legal and other professional services and a $0.4 million increase in the allowance for bad debt.
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Depreciation, Depletion and Amortization Expense
Crude oil and natural gas properties. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $96.3 million for the three months ended March 31, 2016 compared to $54.8 million for the three months ended March 31, 2015. The period-over-period change in DD&A expense related to crude oil and natural gas properties was primarily due to the following (in millions):
Increase in production | $ | 31.7 | ||
Increase in weighted-average depreciation, depletion and amortization rates | 9.8 | |||
Total increase in DD&A expense related to crude oil and natural gas properties | $ | 41.5 | ||
The following table presents our DD&A expense rates for crude oil and natural gas properties:
Three Months Ended March 31, | ||||||||
Operating Region/Area | 2016 | 2015 | ||||||
(per Boe) | ||||||||
Wattenberg Field | $ | 21.72 | $ | 19.81 | ||||
Utica Shale | 8.19 | 10.08 | ||||||
Total weighted-average | 21.08 | 18.92 | ||||||
The increase in the weighted-average DD&A expense rate is a result of the decline in proved developed reserves in 2015 as compared to 2014.
Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $1.1 million for each of the three months ended March 31, 2016 and 2015.
Provision for Uncollectible Notes Receivable
A provision for uncollectible notes receivable of $44.7 million was recorded during the three months ended March 31, 2016 to impair two third-party notes receivable whose collection is not reasonably assured. See Note 3, Fair Value of Financial Instruments - Notes Receivable, to our condensed consolidated financial statements included elsewhere in this report for additional information.
Provision for Income Taxes
See Note 6, Income Taxes, to the accompanying condensed consolidated financial statements included elsewhere in this report for a discussion of the changes in our effective tax rate for the three months ended March 31, 2016 compared to the three months ended March 31, 2015. The effective tax rate of 36.9% benefit on loss for the three months ended March 31, 2016 is based on forecasted pre-tax loss for the year adjusted for permanent differences. The forecasted full year effective tax rate has been applied to the quarter-to-date pre-tax loss resulting in a tax benefit for the period. Because the estimate of full-year income or loss may change from quarter to quarter, the effective tax rate for any particular quarter may not have a meaningful relationship to pre-tax income or loss for the quarter or the actual annual effective tax rate that is determined at the end of the year.
Net Income (Loss)/Adjusted Net Income (Loss)
Net loss for the three months ended March 31, 2016 was $71.5 million compared to net income of $17.1 million for the three months ended March 31, 2015. Adjusted net loss, a non-U.S. GAAP financial measure, was $37.0 million for the three months ended March 31, 2016 compared to adjusted net income of $7.0 million for the same prior year period. The quarter-over-quarter changes in net income (loss) are discussed above, with the most significant changes related to the decrease in commodity price risk management activity income and the increase in DD&A expense and provision for uncollectible notes receivable. These changes similarly impacted adjusted net income (loss), with the exception of the tax effected net change in fair value of unsettled derivatives. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of this non-U.S. GAAP financial measure.
Financial Condition, Liquidity and Capital Resources
Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in debt and equity market transactions and asset sales. For the three months ended March 31, 2016, our primary sources of liquidity were the net proceeds received from the March 2016 public offering of our common stock of $296.6 million, and net cash flows from operating activities of $101.2 million. We used a portion of the net proceeds of the offering to repay all amounts then outstanding on our revolving credit facility and intend to use the remaining amounts to repay the principal amounts owed upon the maturity of the Convertible Notes in May 2016 and for general corporate purposes.
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Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage this volatility through our use of derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. For instruments that mature in three years or less, our debt covenants restrict us from entering into hedges that would exceed 85% of our expected future production from total proved reserves for such related time period (proved developed producing, proved developed non-producing and proved undeveloped). For instruments that mature later than three years, but no more than our designated maximum maturity, our debt covenants limit us from entering into hedges that would exceed 85% of our expected future production from proved developed producing properties during that time period. We may choose not to hedge the maximum amounts permitted under our covenants. Therefore, we may still have significant fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. Given current commodity prices and our hedge position, we expect that positive net settlements on our derivative positions will continue to be a significant positive component of our 2016 cash flows from operations.
Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility. At March 31, 2016, we had a working capital surplus of $239.9 million compared to a surplus of $30.7 million at December 31, 2015. The increase in working capital as of March 31, 2016 is primarily the result of the net proceeds from the March 2016 common stock offering, offset in part by the decrease in the fair value of unsettled derivatives.
In recent periods, including the three months ended March 31, 2016, we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of securities. Accordingly, we ended March 2016 with cash and cash equivalents of $238.5 million and availability under our revolving credit facility of $438.3 million, for a total liquidity position of $676.8 million, compared to $402.2 million at December 31, 2015. These amounts exclude an additional $250 million available under our revolving credit facility, subject to certain terms and conditions of the agreement. The increase in liquidity of $274.6 million, or 68.3%, was primarily attributable to the net proceeds received from the March 2016 public offering of our common stock of $296.6 million, and net cash flows from operating activities of $101.2 million, offset in part by cash paid for capital expenditures of $122.8 million during the three months ended March 31, 2016. Our liquidity position is expected to be reduced by the cash payment of approximately $115 million upon the maturity of our Convertible Notes in May 2016. With our current derivative position, liquidity position and expected cash flows from operations, we believe that we have sufficient capital to fund our operations and planned drilling operations in 2016. We cannot, however, assure sources of capital available to us in the past will be available to us in the future.
In March 2015, we filed an automatic shelf registration statement on Form S-3 with the SEC. Effective upon filing, the shelf provides for the potential sale of an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants or purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital and to have the flexibility to raise such funds in one or more offerings should we perceive market conditions to be favorable. Pursuant to this shelf registration, we sold approximately four million shares of our common stock in March 2015 in an underwritten public offering at a price to us of $50.73 per share and approximately six million shares of our common stock in March 2016 in an underwritten public offering at a price to us of $50.11 per share.
Our revolving credit facility borrowing base is subject to a redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. In September 2015, we completed the semi-annual redetermination of our revolving credit facility by the lenders, which resulted in the reaffirmation of our borrowing base at $700 million. The maturity date of the revolving credit facility is May 2020. However, we elected to maintain the aggregate commitment level at $450 million. We do not currently expect a material change in the borrowing base as a result of the upcoming May 2016 semi-annual redetermination. We had no outstanding balance on our revolving credit facility as of March 31, 2016. While we have added and expect to continue to add producing reserves through our drilling operations, the effect of any such reserve additions on our borrowing base could be offset by other factors including, among other things, a prolonged period of depressed commodity prices or regulatory pressure on lenders to reduce their exposure to exploration and production companies.
Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.25 times the trailing 12 months earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled derivatives, exploration expense, gains (losses) on sales of assets and other non-cash, extraordinary or non-recurring gains (losses) ("EBITDAX") and (ii) an adjusted current ratio of at least 1.0 to 1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of crude oil and natural gas derivative instruments. Additionally, available borrowings under our revolving credit facility are added to the current asset calculation and the current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At March 31, 2016, we were in compliance with all debt covenants with a 1.3 times debt to EBITDAX ratio and a 2.8 to 1.0 current ratio. We expect to remain in compliance throughout the next year.
The indenture governing our 7.75% senior notes due 2022 contains customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. At March 31, 2016, we were in compliance with all covenants and expect to remain in compliance throughout the next year.
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Pursuant to the indenture governing the Convertible Notes, the conversion rights on our Convertible Notes were triggered on November 15, 2015. We have elected to settle the $115 million principal amount of the notes in cash and settle the excess conversion value in shares, as well as cash in lieu of fractional shares. We intend to fund the cash settlement of any such conversion from net proceeds from the March 2016 public offering of our common stock. The “if-converted” value of the Convertible Notes as of March 31, 2016 exceeded the aggregate principal amount by approximately $46.2 million.
See Part I, Item 3, Quantitative and Qualitative Disclosures about Market Risk, for our discussion of credit risk.
Cash Flows
Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities increased by $19.3 million for the three months ended March 31, 2016 compared to the three months ended March 31, 2015, primarily due to the increase in net settlements from our derivative positions of $16.4 million and the increase in changes in assets and liabilities of $2.3 million related to the timing of cash payments and receipts. The key components for the changes in our cash flows provided by operating activities are described in more detail in Results of Operations above.
Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased $17.0 million during the three months ended March 31, 2016, compared to the three months ended March 31, 2015. The increase was primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of assets and liabilities. Adjusted EBITDA, a non-U.S. GAAP financial measure, decreased by $29.4 million during the three months ended March 31, 2016 compared to the three months ended March 31, 2015. The decrease was primarily the result of recording a provision for uncollectible notes receivable of $44.7 million, offset in part by the increase in net settlements from our derivative positions of $16.4 million. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of non-U.S. GAAP financial measures.
Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital expenditures. We would not be able to maintain our current level of crude oil, natural gas and NGLs production and cash flows from operating activities if capital markets were unavailable, commodity prices were to become depressed for a prolonged period and/or the borrowing base under our revolving credit facility was significantly reduced. The occurrence of such an event may result in our election to defer a substantial portion of our planned capital expenditures and could have a material negative impact on our operations in the future.
Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. During the three months ended March 31, 2016, our drilling program consisted of four drilling rigs operating in the horizontal Niobrara and Codell plays in our Wattenberg Field. Net cash used in investing activities of $122.7 million during the three months ended March 31, 2016 was primarily related to cash utilized for our drilling operations, including completion activities. For the full year 2016, we expect that our cash flows from operations will approximate our cash flows from investing activities.
Financing Activities. Net cash from financing activities for the three months ended March 31, 2016 increased by approximately $113.6 million compared to the three months ended March 31, 2015. Net cash from financing activities of $259.2 million for the three months ended March 31, 2016 was primarily related to the $296.6 million received from the issuance of our common stock in March 2016, partially offset by net payments of approximately $37.0 million to pay down amounts borrowed under our revolving credit facility.
Drilling Activity
The following table presents our net developmental drilling activity for the periods shown. Productive wells consist of wells spud, turned-in-line and producing during the period. In-process wells represent wells that have been spud, drilled or are waiting to be completed and/or for gas pipeline connection during the period.
Net Drilling Activity | ||||||||
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
Operating Region/Area | Productive | In-Process | Productive | In-Process | ||||
Development Wells | ||||||||
Wattenberg Field, operated wells | 24.9 | 58.0 | 13.1 | 52.1 | ||||
Wattenberg Field, non-operated wells | 1.5 | 5.5 | 2.5 | 6.4 | ||||
Utica Shale | — | 4.2 | — | 3.0 | ||||
Total drilling activity | 26.4 | 67.7 | 15.6 | 61.5 | ||||
Off-Balance Sheet Arrangements
At March 31, 2016, we had no off-balance sheet arrangements, as defined under SEC rules, that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Commitments and Contingencies
See Note 10, Commitments and Contingencies, to the accompanying condensed consolidated financial statements included elsewhere in this report.
Recent Accounting Standards
See Note 2, Summary of Significant Accounting Policies, to the accompanying condensed consolidated financial statements included elsewhere in this report.
Critical Accounting Policies and Estimates
The preparation of the accompanying condensed consolidated financial statements in conformity with U.S. GAAP required management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenue and expenses.
There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the consolidated financial statements and accompanying notes contained in our 2015 Form 10-K filed with the SEC on February 22, 2016.
Reconciliation of Non-U.S. GAAP Financial Measures
We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDA," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities, and should not be viewed as liquidity
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measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has been only a timing issue from one period to the next as we have not had significant accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. See the condensed consolidated statements of cash flows in the accompanying condensed consolidated financial statements included elsewhere in this report.
Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives and net settlements on commodity derivatives, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of unsettled derivatives. Additionally, other items which are not indicative of future results may be excluded to clearly identify operating trends.
Adjusted EBITDA. We define adjusted EBITDA as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of crude oil and natural gas properties, depreciation, depletion and amortization and accretion of asset retirement obligations, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDA is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), and should not be considered an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDA includes certain non-cash costs incurred by the Company and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDA is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts and others to analyze such things as:
• | operating performance and return on capital as compared to our peers; |
• | financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis; |
• | our ability to generate sufficient cash to service our debt obligations; and |
• | the viability of acquisition opportunities and capital expenditure projects, including the related rate of return. |
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The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure:
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
(in millions) | |||||||
Adjusted cash flows from operations: | |||||||
Adjusted cash flows from operations | $ | 91.0 | $ | 74.0 | |||
Changes in assets and liabilities | 10.2 | 7.9 | |||||
Net cash from operating activities | $ | 101.2 | $ | 81.9 | |||
Adjusted net income (loss): | |||||||
Adjusted net income (loss) | $ | (37.0 | ) | $ | 7.0 | ||
Gain on commodity derivative instruments | 11.1 | 66.7 | |||||
Net settlements on commodity derivative instruments | (66.8 | ) | (50.4 | ) | |||
Tax effect of above adjustments | 21.2 | (6.2 | ) | ||||
Net income (loss) | $ | (71.5 | ) | $ | 17.1 | ||
Adjusted EBITDA to net income (loss): | |||||||
Adjusted EBITDA | $ | 52.9 | $ | 82.3 | |||
Gain on commodity derivative instruments | 11.1 | 66.7 | |||||
Net settlements on commodity derivative instruments | (66.8 | ) | (50.4 | ) | |||
Interest expense, net | (10.3 | ) | (10.6 | ) | |||
Income tax provision | 41.8 | (10.7 | ) | ||||
Impairment of crude oil and natural gas properties | (1.0 | ) | (2.8 | ) | |||
Depreciation, depletion and amortization | (97.4 | ) | (55.8 | ) | |||
Accretion of asset retirement obligations | (1.8 | ) | (1.6 | ) | |||
Net income (loss) | $ | (71.5 | ) | $ | 17.1 | ||
Adjusted EBITDA to net cash from operating activities: | |||||||
Adjusted EBITDA | $ | 52.9 | $ | 82.3 | |||
Interest expense, net | (10.3 | ) | (10.6 | ) | |||
Stock-based compensation | 4.7 | 4.4 | |||||
Amortization of debt discount and issuance costs | 1.8 | 1.8 | |||||
Gain on sale of properties and equipment | (0.1 | ) | — | ||||
Other | 42.0 | (3.9 | ) | ||||
Changes in assets and liabilities | 10.2 | 7.9 | |||||
Net cash from operating activities | $ | 101.2 | $ | 81.9 | |||
Amounts above include results from continuing and discontinued operations.
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PDC ENERGY, INC.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market-Sensitive Instruments and Risk Management
We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks.
Interest Rate Risk
Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 7.75% senior notes due 2022 and our Convertible Notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.
As of March 31, 2016, our interest-bearing deposit accounts included money market accounts, certificates of deposit and checking and savings accounts with various banks. The amount of our interest-bearing cash, cash equivalents and restricted cash as of March 31, 2016 was $200.3 million with a weighted-average interest rate of 0.2%. Based on a sensitivity analysis of our interest-bearing deposits as of March 31, 2016, we estimate that a 1% increase in interest rates would increase interest income for the three months ended March 31, 2016 by approximately $0.5 million.
As of March 31, 2016, we had no outstanding balance on our revolving credit facility.
Commodity Price Risk
We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our derivative policies and procedures are effective in achieving our risk management objectives.
The following table presents our derivative positions related to crude oil and natural gas sales in effect as of March 31, 2016:
Collars | Fixed-Price Swaps | Basis Protection Swaps | |||||||||||||||||||||||||||
Commodity/ Index/ Maturity Period | Quantity (Gas - BBtu (1) Oil - MBbls) | Weighted-Average Contract Price | Quantity (Gas - BBtu (1) Oil - MBbls) | Weighted- Average Contract Price | Quantity (BBtu) (1) | Weighted- Average Contract Price | Fair Value March 31, 2016 (2) (in millions) | ||||||||||||||||||||||
Floors | Ceilings | ||||||||||||||||||||||||||||
Natural Gas | |||||||||||||||||||||||||||||
NYMEX | |||||||||||||||||||||||||||||
2016 | 5,070.0 | $ | 3.87 | $ | 4.22 | 19,440.0 | $ | 3.74 | 20,703.2 | $ | (0.29 | ) | $ | 36.6 | |||||||||||||||
2017 | 7,920.0 | 3.59 | 4.13 | 24,590.0 | 3.62 | 12,000.0 | (0.28 | ) | 27.0 | ||||||||||||||||||||
2018 | 1,230.0 | 3.00 | 3.67 | 17,430.0 | 3.00 | — | — | 2.7 | |||||||||||||||||||||
Total Natural Gas | 14,220.0 | 61,460.0 | 32,703.2 | 66.3 | |||||||||||||||||||||||||
Crude Oil | |||||||||||||||||||||||||||||
NYMEX | |||||||||||||||||||||||||||||
2016 | 1,305.0 | 77.59 | 97.55 | 2,790.0 | 72.21 | — | — | 131.1 | |||||||||||||||||||||
2017 | 960.0 | 54.06 | 73.77 | 3,004.0 | 44.92 | — | — | 11.5 | |||||||||||||||||||||
2018 | 504.0 | 40.00 | 49.90 | 504.0 | 47.08 | — | — | (0.9 | ) | ||||||||||||||||||||
Total Crude Oil | 2,769.0 | 6,298.0 | — | 141.7 | |||||||||||||||||||||||||
Total Natural Gas and Crude Oil | $ | 208.0 | |||||||||||||||||||||||||||
____________
(1) | A standard unit of measurement for natural gas (one BBtu equals one MMcf). |
(2) | Approximately 33.9% of the fair value of our derivative assets and 9.2% of the fair value of our derivative liabilities were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value Measurements, to the condensed consolidated financial statements included elsewhere in this report. |
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PDC ENERGY, INC.
The following table presents average NYMEX and CIG closing prices for crude oil and natural gas for the periods identified, as well as average sales prices we realized for our crude oil, natural gas and NGLs production:
Three Months Ended | Year Ended | ||||||
March 31, 2016 | December 31, 2015 | ||||||
Average Index Closing Price: | |||||||
Crude oil (per Bbl) | |||||||
NYMEX | $ | 33.45 | $ | 48.80 | |||
Natural gas (per MMBtu) | |||||||
NYMEX | $ | 2.09 | $ | 2.66 | |||
CIG | 1.79 | 2.44 | |||||
TETCO M-2 (1) | 1.20 | 1.49 | |||||
Average Sales Price Realized: | |||||||
Excluding net settlements on derivatives | |||||||
Crude oil (per Bbl) | $ | 28.29 | $ | 40.14 | |||
Natural gas (per Mcf) | 1.39 | 2.04 | |||||
NGLs (per Bbl) | 7.37 | 10.72 | |||||
_____________
(1) TETCO M-2 is an index price upon which a majority of our natural gas produced in the Utica Shale is sold.
Based on a sensitivity analysis as of March 31, 2016, it was estimated that a 10% increase in natural gas and crude oil prices, inclusive of basis, over the entire period for which we have derivatives in place, would have resulted in a decrease in the fair value of our derivative positions of $55.1 million, whereas a 10% decrease in prices would have resulted in an increase in fair value of $55.4 million.
See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to significant credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties.
Our Oil and Gas Exploration and Production segment's crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. Amounts due to our Gas Marketing segment are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions and end-users in various industries. As commodity prices continue to remain depressed, certain customers under our Gas Marketing segment have begun and continue to experience financial distress, which has led to certain contractual defaults. To date, we have had no material counterparty default losses relating to customers in either segment.
We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our derivative financial instruments. See Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for more detail on our derivative financial instruments.
Disclosure of Limitations
Because the information above included only those exposures that existed at March 31, 2016, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time, and interest rates and commodity prices at the time.
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PDC ENERGY, INC.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of March 31, 2016, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e).
Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2016.
Changes in Internal Control over Financial Reporting
During the three months ended March 31, 2016, we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
PART II
ITEM 1. LEGAL PROCEEDINGS
Information regarding our legal proceedings can be found in Note 10, Commitments and Contingencies – Litigation, to our condensed consolidated financial statements included elsewhere in this report.
ITEM 1A. RISK FACTORS
We face many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described under Item 1A, Risk Factors, of our 2015 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Period | Total Number of Shares Purchased (1) | Average Price Paid per Share | |||||
January 1 - 31, 2016 | 22,928 | $ | 51.55 | ||||
February 1 - 29, 2016 | — | — | |||||
March 1 - 31, 2016 | 653 | 56.48 | |||||
Total first quarter purchases | 23,581 | 51.69 | |||||
__________
(1) | Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. |
ITEM 3. DEFAULTS UPON SENIOR SECURITIES - None.
ITEM 4. MINE SAFETY DISCLOSURES - Not applicable.
ITEM 5. OTHER INFORMATION - None.
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PDC ENERGY, INC.
ITEM 6. EXHIBITS
Incorporated by Reference | ||||||||||||
Exhibit Number | Exhibit Description | Form | SEC File Number | Exhibit | Filing Date | Filed Herewith | ||||||
31.1 | Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
31.2 | Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
32.1** | Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. | |||||||||||
101.INS | XBRL Instance Document | X | ||||||||||
101.SCH | XBRL Taxonomy Extension Schema Document | X | ||||||||||
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | X | ||||||||||
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | X | ||||||||||
101.LAB | XBRL Taxonomy Extension Label Linkbase Document | X | ||||||||||
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | X | ||||||||||
*Management contract or compensatory arrangement. | ||||||||||||
** Furnished herewith. | ||||||||||||
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PDC ENERGY, INC.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PDC Energy, Inc. | |
(Registrant) | |
Date: May 6, 2016 | /s/ Barton R. Brookman |
Barton R. Brookman | |
President and Chief Executive Officer | |
(principal executive officer) | |
/s/ Gysle R. Shellum | |
Gysle R. Shellum | |
Chief Financial Officer | |
(principal financial officer) | |
/s/ R. Scott Meyers | |
R. Scott Meyers | |
Chief Accounting Officer | |
(principal accounting officer) | |
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