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 September 30, 2016March 31, 2017
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"filer," "smaller reporting company," and "smaller reporting"emerging growth company" in Rule 12b-2 of the Exchange Act.
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| |
Large accelerated filer x | Accelerated filer o |
Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
| Emerging growth company o |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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: 56,266,14765,855,290 shares of the Company's Common Stock ($0.01 par value) were outstanding as of October 17, 2016.April 18, 2017.
PDC ENERGY, INC.
TABLE OF CONTENTS
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| PART I – FINANCIAL INFORMATION | | Page |
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Item 1. | Financial Statements | | |
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Item 2. | | | |
Item 3. | | | |
Item 4. | | | |
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PART II – OTHER INFORMATION |
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Item 1. | | | |
Item 1A. | | | |
Item 2. | | | |
Item 3. | | | |
Item 4. | | | |
Item 5. | | | |
Item 6. | | | |
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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"), and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations, and prospects. All statements other than statements of historical factsfact 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. TheseForward-looking statements relate to,may include, among other things: the closing of pending transactions and the effects of such transactions, including the fact that the pending Delaware Basin acquisition is subject to continuing diligence between the parties and accordingly, may not occur within the expected timeframe or at all; estimated futurethings, statements regarding future: reserves, production, (including the components of such production), sales, expenses,costs, cash flows, liquidity and balance sheet attributes; estimated crude oil, natural gasearnings; drilling locations and natural gas liquids (“NGLs”) reserves; the impact of prolonged depressed commodity prices,growth opportunities; capital investments and projects, including potentially reduced production and associated cash flow; anticipated capital projects, expenditures and opportunities; 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; expected positive net settlements on derivatives for the remainder of 2016; that we expect quarter-over-quarter production growth; future exploration, drilling and development activities, including non-operated activity, the number of drilling rigs we expect to run and lateral lengths of wells, including thedrill times and number of rigs we expect to run in 2017 in the Delaware Basin; expected 2016 productionemployed; rates of return; operational enhancements and cash flow rangesefficiencies; management of lease expiration issues; financial ratios; and timing of turn-in-lines; our evaluation method of our customers'midstream capacity 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 covenants; 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.related curtailments.
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;demand and prices for the products we produce;
volatility of commodity prices for crude oil, natural gas, and NGLsnatural gas liquids ("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 toof 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;
losses from our gas marketing business exceeding our expectations;
difficulties in integrating our operations as a result of any significant acquisitions, including our recent acquisitions in the Delaware Basin;
increases or changes in operating costs, severance and ad valorem taxes, and increases or changes in drilling, completion, and facilities costs;
increases or adverse changes in construction costs and procurement costs associated with future build out of midstream-related assets;
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;investments;
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, 20152016 (the "2015"2016 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 22, 2016,28, 2017, 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)
| | | | September 30, 2016 | | December 31, 2015 | | March 31, 2017 | | December 31, 2016 |
Assets | | | | | | | | |
Current assets: | | | | | | | | |
Cash and cash equivalents | | $ | 1,197,692 |
| | $ | 850 |
| | $ | 207,624 |
| | $ | 244,100 |
|
Short-term investments | | — |
| 49,890 |
| | — |
|
Accounts receivable, net | | 99,895 |
| | 104,274 |
| | 122,484 |
| | 143,392 |
|
Fair value of derivatives | | 65,604 |
| | 221,659 |
| | 27,047 |
| | 8,791 |
|
Prepaid expenses and other current assets | | 4,854 |
| | 5,266 |
| | 4,726 |
| | 3,542 |
|
Total current assets | | 1,368,045 |
| | 332,049 |
| | 411,771 |
| | 399,825 |
|
Properties and equipment, net | | 1,932,274 |
| | 1,940,552 |
| | 4,098,463 |
| | 4,008,266 |
|
Fair value of derivatives | | 8,423 |
| | 44,387 |
| | 13,921 |
| | 2,386 |
|
Goodwill | | | 56,058 |
| | 62,041 |
|
Other assets | | 108,538 |
| | 53,555 |
| | 12,917 |
| | 13,324 |
|
Total Assets | | $ | 3,417,280 |
| | $ | 2,370,543 |
| | $ | 4,593,130 |
| | $ | 4,485,842 |
|
| | | | | | | | |
Liabilities and Shareholders' Equity | | | | | |
Liabilities and Stockholders' Equity | | | | | |
Liabilities | | | | | | | | |
Current liabilities: | | | | | | | | |
Accounts payable | | $ | 62,350 |
| | $ | 92,613 |
| | $ | 144,440 |
| | $ | 66,322 |
|
Production tax liability | | 22,141 |
| | 26,524 |
| | 25,065 |
| | 24,767 |
|
Fair value of derivatives | | 22,563 |
| | 1,595 |
| | 26,495 |
| | 53,595 |
|
Funds held for distribution | | 51,107 |
| | 29,894 |
| | 76,067 |
| | 71,339 |
|
Current portion of long-term debt | | — |
| | 112,940 |
| |
Accrued interest payable | | 19,364 |
| | 9,057 |
| | 18,977 |
| | 15,930 |
|
Other accrued expenses | | 41,756 |
| | 28,709 |
| | 26,938 |
| | 38,625 |
|
Total current liabilities | | 219,281 |
| | 301,332 |
| | 317,982 |
| | 270,578 |
|
Long-term debt | | 1,041,575 |
| | 529,437 |
| | 1,046,461 |
| | 1,043,954 |
|
Deferred income taxes | | 44,340 |
| | 143,452 |
| | 427,205 |
| | 400,867 |
|
Asset retirement obligation | | 82,509 |
| | 84,032 |
| |
Asset retirement obligations | | | 78,162 |
| | 82,612 |
|
Fair value of derivatives | | 17,885 |
| | 695 |
| | 4,302 |
| | 27,595 |
|
Other liabilities | | 25,630 |
| | 24,398 |
| | 47,841 |
| | 37,482 |
|
Total liabilities | | 1,431,220 |
| | 1,083,346 |
| | 1,921,953 |
| | 1,863,088 |
|
| | | | | | | | |
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, 56,280,544 and 40,174,776 issued as of September 30, 2016 and December 31, 2015, respectively | | 563 |
| | 402 |
| |
Stockholders' equity | | | | | |
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,797,748 and 65,704,568 issued as of March 31, 2017 and December 31, 2016, respectively | | | 658 |
| | 657 |
|
Additional paid-in capital | | 1,796,664 |
| | 907,382 |
| | 2,492,276 |
| | 2,489,557 |
|
Retained earnings | | 190,133 |
| | 380,422 |
| | 180,354 |
| | 134,208 |
|
Treasury shares - at cost, 25,854 and 20,220 as of September 30, 2016 and December 31, 2015, respectively | | (1,300 | ) | | (1,009 | ) | |
Total shareholders' equity | | 1,986,060 |
| | 1,287,197 |
| |
Total Liabilities and Shareholders' Equity | | $ | 3,417,280 |
| | $ | 2,370,543 |
| |
Treasury shares - at cost, 34,433 and 28,763 as of March 31, 2017 and December 31, 2016, respectively | | | (2,111 | ) | | (1,668 | ) |
Total stockholders' equity | | | 2,671,177 |
| | 2,622,754 |
|
Total Liabilities and Stockholders' Equity | | | $ | 4,593,130 |
| | $ | 4,485,842 |
|
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 September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 |
Revenues | | | | | | | | | | | | |
Crude oil, natural gas and NGLs sales | | $ | 141,805 |
| | $ | 104,483 |
| | $ | 328,013 |
| | $ | 275,520 |
| |
Sales from natural gas marketing | | 2,678 |
| | 2,580 |
| | 6,728 |
| | 8,336 |
| |
Commodity price risk management gain (loss), net | | 19,397 |
| | 123,549 |
| | (62,348 | ) | | 141,170 |
| |
Well operations, pipeline income and other | | 10 |
| | 488 |
| | 2,425 |
| | 1,666 |
| |
Crude oil, natural gas, and NGLs sales | | | $ | 189,692 |
| | $ | 75,367 |
|
Commodity price risk management gain, net of settlements | | | 80,704 |
| | 11,056 |
|
Other income | | | 3,311 |
| | 4,408 |
|
Total revenues | | 163,890 |
| | 231,100 |
| | 274,818 |
| | 426,692 |
| | 273,707 |
| | 90,831 |
|
Costs, expenses and other | | | | | | | | | | | | |
Lease operating expenses | | 14,001 |
| | 13,825 |
| | 43,006 |
| | 42,749 |
| | 19,789 |
| | 15,330 |
|
Production taxes | | 9,568 |
| | 5,476 |
| | 19,682 |
| | 13,206 |
| | 12,399 |
| | 4,071 |
|
Transportation, gathering and processing expenses | | 5,048 |
| | 3,938 |
| | 13,554 |
| | 6,584 |
| | 5,902 |
| | 4,041 |
|
Cost of natural gas marketing | | 3,092 |
| | 2,781 |
| | 7,795 |
| | 8,875 |
| |
Exploration expense | | 241 |
| | 252 |
| | 688 |
| | 812 |
| |
General and administrative expense | | | 26,315 |
| | 22,779 |
|
Exploration, geologic, and geophysical expense | | | 954 |
| | 210 |
|
Depreciation, depletion and amortization | | | 109,316 |
| | 97,388 |
|
Impairment of properties and equipment | | 933 |
| | 154,031 |
| | 6,104 |
| | 161,207 |
| | 2,193 |
| | 1,001 |
|
General and administrative expense | | 32,510 |
| | 20,277 |
| | 78,868 |
| | 62,050 |
| |
Depreciation, depletion and amortization | | 112,927 |
| | 80,947 |
| | 317,329 |
| | 206,873 |
| |
Provision for uncollectible notes receivable | | (700 | ) | | — |
| | 44,038 |
| | — |
| |
Accretion of asset retirement obligations | | 1,777 |
| | 1,594 |
| | 5,400 |
| | 4,742 |
| | 1,768 |
| | 1,812 |
|
Gain on sale of properties and equipment | | (219 | ) | | (74 | ) | | (43 | ) | | (302 | ) | | (160 | ) | | (84 | ) |
Total cost, expenses and other | | 179,178 |
| | 283,047 |
| | 536,421 |
| | 506,796 |
| |
Loss from operations | | (15,288 | ) | | (51,947 | ) | | (261,603 | ) | | (80,104 | ) | |
Provision for uncollectible notes receivable | | | — |
| | 44,738 |
|
Other expenses | | | 3,528 |
| | 2,578 |
|
Total costs, expenses and other | | | 182,004 |
| | 193,864 |
|
Income (loss) from operations | | | 91,703 |
| | (103,033 | ) |
Interest expense | | (20,193 | ) | | (12,092 | ) | | (42,759 | ) | | (35,384 | ) | | (19,467 | ) | | (11,894 | ) |
Interest income | | 140 |
| | 1,378 |
| | 1,875 |
| | 3,626 |
| | 240 |
| | 1,558 |
|
Loss before income taxes | | (35,341 | ) | | (62,661 | ) | | (302,487 | ) | | (111,862 | ) | |
Provision for income taxes | | 12,032 |
| | 21,167 |
| | 112,198 |
| | 40,560 |
| |
Net loss | | $ | (23,309 | ) | | $ | (41,494 | ) | | $ | (190,289 | ) | | $ | (71,302 | ) | |
Income (loss) before income taxes | | | 72,476 |
| | (113,369 | ) |
Income tax (expense) benefit | | | (26,330 | ) | | 41,839 |
|
Net income (loss) | | | $ | 46,146 |
| | $ | (71,530 | ) |
| | | | | | | | | | | | |
Earnings per share: | | | | | | | | | | | | |
Basic | | $ | (0.48 | ) | | $ | (1.04 | ) | | $ | (4.16 | ) | | $ | (1.84 | ) | | $ | 0.70 |
| | $ | (1.72 | ) |
Diluted | | $ | (0.48 | ) | | $ | (1.04 | ) | | $ | (4.16 | ) | | $ | (1.84 | ) | | $ | 0.70 |
| | $ | (1.72 | ) |
| | | | | | | | | | | | |
Weighted-average common shares outstanding: | | | | | | | | | | | | |
Basic | | 48,839 |
| | 40,085 |
| | 45,741 |
| | 38,837 |
| | 65,749 |
| | 41,608 |
|
Diluted | | 48,839 |
| | 40,085 |
| | 45,741 |
| | 38,837 |
| | 66,117 |
| | 41,608 |
|
| | | | | | | | | | | | |
See accompanying Notes to Condensed Consolidated Financial Statements
2
PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited; in thousands)
| | | | Nine Months Ended September 30, | | Three Months Ended March 31, |
| | 2016 | | 2015 | | 2017 | | 2016 |
Cash flows from operating activities: | | | | | | | | |
Net loss | | $ | (190,289 | ) | | $ | (71,302 | ) | |
Adjustments to net loss to reconcile to net cash from operating activities: | | | | | |
Net change in fair value of unsettled derivatives | | 230,177 |
| | 21,322 |
| |
Net income (loss) | | | $ | 46,146 |
| | $ | (71,530 | ) |
Adjustments to net income (loss) to reconcile to net cash from operating activities: | | | | | |
Net change in fair value of unsettled commodity derivatives | | | (80,153 | ) | | 55,770 |
|
Depreciation, depletion and amortization | | 317,329 |
| | 206,873 |
| | 109,316 |
| | 97,388 |
|
Provision for uncollectible notes receivable | | 44,038 |
| | — |
| |
Impairment of properties and equipment | | 6,104 |
| | 161,207 |
| | 2,193 |
| | 1,001 |
|
Accretion of asset retirement obligation | | 5,400 |
| | 4,742 |
| |
Stock-based compensation | | 15,205 |
| | 14,278 |
| |
Accretion of asset retirement obligations | | | 1,768 |
| | 1,812 |
|
Non-cash stock-based compensation | | | 4,454 |
| | 4,682 |
|
Gain on sale of properties and equipment | | (43 | ) | | (302 | ) | | (160 | ) | | (84 | ) |
Amortization of debt discount and issuance costs | | 12,951 |
| | 5,308 |
| | 3,184 |
| | 1,754 |
|
Deferred income taxes | | (114,136 | ) | | (44,770 | ) | | 26,280 |
| | (43,372 | ) |
Non-cash interest income | | (1,194 | ) | | (3,624 | ) | |
Provision for uncollectible notes receivable | | | — |
| | 44,738 |
|
Other | | 668 |
| | (174 | ) | | 722 |
| | (1,202 | ) |
Changes in assets and liabilities | | 34,621 |
| | (10,552 | ) | | 25,750 |
| | 10,193 |
|
Net cash from operating activities | | 360,831 |
| | 283,006 |
| | 139,500 |
| | 101,150 |
|
Cash flows from investing activities: | | | | | | | | |
Capital expenditures | | (353,722 | ) | | (489,036 | ) | |
Acquisition of crude oil and natural gas properties | | (100,000 | ) | | — |
| |
Capital expenditures for development of crude oil and natural gas properties | | | (129,826 | ) | | (122,309 | ) |
Capital expenditures for other properties and equipment | | | (821 | ) | | (450 | ) |
Acquisition of crude oil and natural gas properties, including settlement adjustments | | | 6,181 |
| | — |
|
Proceeds from sale of properties and equipment | | 4,945 |
| | 319 |
| | 737 |
| | 90 |
|
Purchases of short-term investments | | | (49,890 | ) | | — |
|
Net cash from investing activities | | (448,777 | ) | | (488,717 | ) | | (173,619 | ) | | (122,669 | ) |
Cash flows from financing activities: | | | | | | | | |
Proceeds from sale of equity, net of issuance cost | | 855,072 |
| | 202,851 |
| |
Proceeds from senior notes | | 392,250 |
| | — |
| |
Proceeds from convertible senior notes | | 193,979 |
| | — |
| |
Proceeds from issuance of equity, net of issuance cost | | | (8 | ) | | 296,578 |
|
Proceeds from revolving credit facility | | 85,000 |
| | 325,000 |
| | — |
| | 85,000 |
|
Repayment of revolving credit facility | | (122,000 | ) | | (331,000 | ) | | — |
| | (122,000 | ) |
Redemption of convertible notes | | (115,000 | ) | | — |
| |
Other | | (4,513 | ) | | (3,516 | ) | | (2,349 | ) | | (364 | ) |
Net cash from financing activities | | 1,284,788 |
| | 193,335 |
| | (2,357 | ) | | 259,214 |
|
Net change in cash and cash equivalents | | 1,196,842 |
| | (12,376 | ) | | (36,476 | ) | | 237,695 |
|
Cash and cash equivalents, beginning of period | | 850 |
| | 16,066 |
| | 244,100 |
| | 850 |
|
Cash and cash equivalents, end of period | | $ | 1,197,692 |
| | $ | 3,690 |
| | $ | 207,624 |
| | $ | 238,545 |
|
| | | | | | | | |
Supplemental cash flow information: | | | | | | | | |
Cash payments for: | | | | | |
Cash payments (receipts) for: | | | | | |
Interest, net of capitalized interest | | $ | 22,975 |
| | $ | 23,467 |
| | $ | 13,224 |
| | $ | 599 |
|
Income taxes | | 167 |
| | 9,936 |
| | (39 | ) | | — |
|
Non-cash investing and financing activities: | | | | | | | | |
Change in accounts payable related to purchases of properties and equipment | | $ | (31,497 | ) | | $ | (68,529 | ) | | $ | 69,604 |
| | $ | (23,544 | ) |
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals | | 1,137 |
| | 1,642 |
| |
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals | | | 1,233 |
| | 404 |
|
Purchase of properties and equipment under capital leases | | 1,231 |
| | 1,479 |
| | 1,190 |
| | 635 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
3
PDC ENERGY, INC.
Condensed Consolidated Statements of Equity
(unaudited; in thousands, except share and per share data)
|
| | | | | | | | |
Nine Months Ended September 30, | | 2016 | | 2015 |
Common shares, issued: | | | | |
Shares beginning of period | | 40,174,776 |
| | 35,927,985 |
|
Shares issued pursuant to sale of equity | | 15,799,906 |
| | 4,002,000 |
|
Exercise of stock options | | 46,084 |
| | — |
|
Issuance of stock awards, net of forfeitures | | 259,778 |
| | 191,623 |
|
Shares end of period | | 56,280,544 |
| | 40,121,608 |
|
Treasury shares: | | | | |
Shares beginning of period | | 20,220 |
| | 21,643 |
|
Purchase of treasury shares | | 90,695 |
| | 93,898 |
|
Issuance of treasury shares | | (91,895 | ) | | (97,995 | ) |
Non-employee directors' deferred compensation plan | | 6,834 |
| | 4,872 |
|
Shares end of period | | 25,854 |
| | 22,418 |
|
Common shares outstanding | | 56,254,690 |
| | 40,099,190 |
|
| | | | |
Equity: | | | | |
Shareholders' equity | | | | |
Preferred shares, par value $0.01 per share: | | | | |
Balance beginning and end of period | | $ | — |
| | $ | — |
|
Common shares, par value $0.01 per share: | | | | |
Balance beginning of period | | 402 |
| | 359 |
|
Shares issued pursuant to sale of equity and note conversion | | 158 |
| | 40 |
|
Issuance of stock awards, net of forfeitures | | 3 |
| | 2 |
|
Balance end of period | | 563 |
| | 401 |
|
Additional paid-in capital: | | | | |
Balance beginning of period | | 907,383 |
| | 689,209 |
|
Convertible debt discount, net of issuance costs and tax | | 23,264 |
| | — |
|
Proceeds from sale of equity, net of issuance costs | | 854,932 |
| | 202,811 |
|
Stock-based compensation expense | | 15,202 |
| | 14,419 |
|
Issuance of treasury shares | | (5,180 | ) | | (4,633 | ) |
Tax impact of stock-based compensation | | 1,063 |
| | 1,232 |
|
Balance end of period | | 1,796,664 |
| | 903,038 |
|
Retained earnings: | | | | |
Balance beginning of period | | 380,422 |
| | 448,702 |
|
Net loss | | (190,289 | ) | | (71,302 | ) |
Balance end of period | | 190,133 |
| | 377,400 |
|
Treasury shares, at cost: | | | | |
Balance beginning of period | | (1,009 | ) | | (911 | ) |
Purchase of treasury shares | | (5,106 | ) | | (4,575 | ) |
Issuance of treasury shares | | 5,179 |
| | 4,632 |
|
Non-employee directors' deferred compensation plan | | (364 | ) | | (249 | ) |
Balance end of period | | (1,300 | ) | | (1,103 | ) |
Total shareholders' equity | | $ | 1,986,060 |
| | $ | 1,279,736 |
|
| | | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016March 31, 2017
(unaudited)
NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION
PDC Energy, Inc. (the("PDC", 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, beginning in December 2016, the Delaware Basin in Reeves and Culberson Counties, Texas. We also have operations in the Utica Shale in southeastern Ohio.Southeastern Ohio, although management expects to begin the process of divesting these properties later in 2017. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our OhioDelaware Basin operations are currently focused in the Utica Shale play. In addition, we currently have a pending acquisition in the Delaware Basin in Texas. See Note 6, Pending Acquisition.Wolfcamp zones. As of September 30, 2016,March 31, 2017, we owned an interest in approximately 3,0002,900 gross productive wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Beginning with the first quarter of 2017, our gas marketing segment does not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business segments: Oil and, Gas Exploration and Production and Gas Marketing.therefore, all of our operations are presented as a single segment for all periods presented.
The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiary Riley Natural Gas ("RNG")subsidiaries, 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, (consistingconsisting of only normal recurring adjustments)adjustments, necessary for a fair statement 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, 20152016 condensed consolidated balance sheet data was derived from audited statements, but does not include all 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 20152016 Form 10-K. Our results of operations and cash flows for the three and nine months ended September 30, 2016March 31, 2017, are not necessarily indicative of the results to be expected for the full year or any other future period.
Certain immaterial reclassifications have been made to our prior period statement of operations to conform to the current period presentation. The reclassifications had no impact on previously reported cash flows, net earnings, earnings per share or stockholders' equity.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board ("FASB")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)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. In December 2016, the FASB issued technical corrections and improvements to the standard. 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 evaluatingin the impact these changes may haveprocess of assessing potential impacts of the new standard on our condensed consolidated financial statements.existing revenue recognition criteria, as well as on related revenue recognition disclosures.
In August 2014, the FASB issued a new standard related to the disclosure
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
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 12 months, the accounting update requires lessees to recognize ana right-of-use asset and lease liability 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 evaluatingin the process of assessing 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
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
after December 15, 2016, and interim periods within those years, 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 August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensedconsolidated financial statements.
In January 2017, the FASB issued an accounting update clarifying the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This guidance is to be applied using a prospective method and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.
In January 2017, the FASB issued an accounting update to simplify the subsequent measurement of goodwill. The update eliminates a step in the determination of whether goodwill should be considered impaired. The annual and/or interim assessments are still required to be completed. The guidance is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.
NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTSBUSINESS COMBINATION
DeterminationDelaware Basin Acquisition. On December 6, 2016, we closed on an acquisition which has been accounted for as a business combination. The transaction was for the purchase of Fair Value
Ourapproximately 57,900 net acres, approximately 30 wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion, comprised of approximately $946.0 million in cash, including the payment of $40.0 million of debt of the seller at closing and other purchase price adjustments, and 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed. The estimated fair value measurementsof assets acquired and liabilities assumed in the acquisition presented below are estimated pursuantpreliminary and subject to a fair value hierarchy that requires us to maximizecustomary additional post-closing adjustments as more detailed analysis associated with the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchyacquired properties is based upon the transparency of inputs to the valuation of an asset or liability ascompleted. As of the measurement date givingof this report, the highest priority to quoted pricesfinal settlement statement has been agreed upon with the sellers. We are 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 levelsprocess of finalizing 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 valuationvalues of the assets acquired and liabilities assumed and their placement withinexpect to keep the fair value hierarchy levels. The three levelstransaction open through the second quarter of inputs2017 to ensure that may be used to measure fair valueany post-closing adjustments associated with the period through final settlement are defined as:
Level 1 – Quoted prices (unadjusted) for identical assets or liabilitiesappropriately reflected in active markets.the final purchase price allocation.
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.5
Derivative Financial Instruments
We measure the fair value of our derivative instruments based upon 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.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016March 31, 2017
(unaudited)
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:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 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 | $ | 49,021 |
| | $ | 24,582 |
| | $ | 73,603 |
| | $ | 174,657 |
| | $ | 91,288 |
| | $ | 265,945 |
|
Basis protection derivative contracts | 424 |
| | — |
| | 424 |
| | 101 |
| | — |
| | 101 |
|
Total assets | 49,445 |
| | 24,582 |
| | 74,027 |
| | 174,758 |
| | 91,288 |
| | 266,046 |
|
Liabilities: | | | | | | | | | | | |
Commodity-based derivative contracts | 30,917 |
| | 8,650 |
| | 39,567 |
| | 738 |
| | — |
| | 738 |
|
Basis protection derivative contracts | 881 |
| | — |
| | 881 |
| | 1,552 |
| | — |
| | 1,552 |
|
Total liabilities | 31,798 |
| | 8,650 |
| | 40,448 |
| | 2,290 |
| | — |
| | 2,290 |
|
Net asset | $ | 17,647 |
| | $ | 15,932 |
| | $ | 33,579 |
| | $ | 172,468 |
| | $ | 91,288 |
| | $ | 263,756 |
|
| | | | | | | | | | | |
The following table presents a reconciliation of our Level 3 assets measured at fair value:
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in thousands) |
Fair value, net asset beginning of period | | $ | 27,285 |
| | $ | 58,256 |
| | $ | 91,288 |
| | $ | 62,356 |
|
Changes in fair value included in condensed consolidated statement of operations line item: | | | | | | | | |
Commodity price risk management gain (loss), net | | 4,234 |
| | 38,085 |
| | (16,023 | ) | | 42,525 |
|
Sales from natural gas marketing | | — |
| | 51 |
| | (20 | ) | | 51 |
|
Settlements included in statement of operations line items: | | | | | | | | |
Commodity price risk management gain (loss), net | | (15,587 | ) | | (12,530 | ) | | (59,243 | ) | | (21,063 | ) |
Sales from natural gas marketing | | — |
| | — |
| | (70 | ) | | (7 | ) |
Fair value, net asset end of period | | $ | 15,932 |
| | $ | 83,862 |
| | $ | 15,932 |
| | $ | 83,862 |
|
| | | | | | | | |
Net change in fair value of unsettled derivatives included in condensed consolidated statement of operations line item: | | | | | | | | |
Commodity price risk management gain (loss), net | | $ | (2,240 | ) | | $ | 34,564 |
| | $ | (8,273 | ) | | $ | 31,794 |
|
| | | | | | | | |
The significant unobservable input used indetails of the fair value measurementestimated purchase price and the preliminary allocation of our derivative contracts is the implied volatility curve,purchase price for the transaction, 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 during the periods covered by this report.reflects certain post-closing adjustments, are presented below (in thousands):
Non-Derivative Financial Assets and Liabilities |
| | | |
| March 31, 2017 |
Acquisition costs: | |
Cash, net of cash acquired | $ | 905,962 |
|
Retirement of seller's debt | 40,000 |
|
Total cash consideration | 945,962 |
|
Common stock, 9.4 million shares | 690,702 |
|
Other purchase price adjustments | 1,025 |
|
Total acquisition costs | $ | 1,637,689 |
|
| |
Recognized amounts of identifiable assets acquired and liabilities assumed: | |
Assets acquired: | |
Current assets | $ | 7,173 |
|
Crude oil and natural gas properties - proved | 216,000 |
|
Crude oil and natural gas properties - unproved | 1,721,334 |
|
Infrastructure, pipeline, and other | 33,695 |
|
Construction in progress | 12,148 |
|
Goodwill | 56,058 |
|
Total assets acquired | 2,046,408 |
|
Liabilities assumed: | |
Current liabilities | (24,519 | ) |
Asset retirement obligations | (4,248 | ) |
Deferred tax liabilities, net | (379,952 | ) |
Total liabilities assumed | (408,719 | ) |
Total identifiable net assets acquired | $ | 1,637,689 |
|
The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due tomeasurements of assets acquired and liabilities assumed are based on inputs that are not observable in the short-term maturitiesmarket, and therefore represent Level 3 inputs. The fair values 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 indicateasset retirement obligations were measured using valuation techniques that convert future cash flows to a possible decline insingle discounted amount. Significant inputs to the recoverabilityvaluation 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 properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are the most sensitive and subject to change.
This acquisition was accounted for under the acquisition method. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred.
Goodwill. Goodwill is calculated as the excess of the purchase price over the fair value of net assets acquired and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired were the acquisition of an element of a workforce and the expected value from operations of the Delaware Basin acquisition to be derived in the future. The amount of goodwill recorded related to the Delaware Basin acquisition has decreased as compared to the initial amount recorded as of December 31, 2016, due to customary purchase price allocations. Such amounts will be sold.finalized with final purchase accounting. Any value assigned to goodwill is not expected to be deductible for income tax purposes.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016March 31, 2017
(unaudited)
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 September 30, 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 September 30, 2016, we estimate the fair value of the portion of our long-term debt related to our 1.125% senior notes due 2021 to be $214.8 million, or 107.4% of par value, 6.125% senior notes due 2024 to be $415.6 million, or 103.9% of par value, and 7.75% senior notes due 2022 to be $530.3 million, or 106.1% 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 related 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 September 30, 2016, taking into account the estimated likelihood of nonperformance.
The following table presents the counterparties that expose us to credit risk as of September 30, 2016 with regard to our derivative assets:
changes in goodwill:
|
| | | | |
Counterparty Name | | Fair Value of Derivative Assets |
| | (in thousands) |
Canadian Imperial Bank of Commerce (1) | | $ | 21,343 |
|
JP Morgan Chase Bank, N.A (1) | | 17,929 |
|
Bank of Nova Scotia (1) | | 15,166 |
|
Wells Fargo Bank, N.A. (1) | | 9,891 |
|
NATIXIS (1) | | 7,171 |
|
Other lenders in our revolving credit facility | | 2,491 |
|
Various (2) | | 36 |
|
Total | | $ | 74,027 |
|
| | |
__________
(1)Major lender in our revolving credit facility. See Note 8, Long-Term Debt.
(2)Represents a total of two counterparties. |
| | | |
| Amount |
| (in thousands) |
| |
Balance at beginning of period, January 1, 2017 | $ | 62,041 |
|
Purchase price adjustments, net of tax | (5,983 | ) |
Balance at end of period, March 31, 2017 | $ | 56,058 |
|
Cash and Cash Equivalents.With the creation of goodwill from this transaction, we will perform our annual evaluation of goodwill for impairment on an annual basis or when a triggering event occurs, beginning in 2017. We consider all highly liquid instruments purchased with an original maturity of three monthsevaluate goodwill for impairment by either performing a qualitative evaluation or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess oftwo-step quantitative test, which involves comparing the FDIC insurance limits at September 30, 2016. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
Notes Receivable. The following table presents information regarding a note receivable outstanding as of September 30, 2016:
|
| | | |
| Amount |
| (in thousands) |
Note receivable: | |
Principal outstanding, December 31, 2015 | $ | 43,069 |
|
Paid-in-kind interest | 969 |
|
Principal outstanding, September 30, 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 million, bearing interest at varying rates beginning at 8%, and increasing annually. Pursuantestimated fair value to the Note agreement, interest is payable quarterly, in arrears, commencing in December 2014 and continuing oncarrying value. In either case, the last business dayvaluation 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 Interestgoodwill will be added to the outstanding principal amount of the Note. As of September 30, 2016, the issuer of the Note had elected the PIK Interest option. The principala significant estimate as such methods incorporate forward-looking assumptions 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. If an event of default occurs under the Note agreement, the Note must be repaid prior to maturity. Legally, the Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets; however, we believe that collection of the Note is not reasonably assured.
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 as of March 31, 2016 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 existing 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 million outstanding balance as of March 31, 2016, which was included in the condensed consolidated balance sheet line item other assets. As of September 30, 2016, there has been no change to our assessment of the collectibility of the note or related interest since March 31, 2016. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Note and are accounting for the Note under the cash basis method.
Under the effective interest method, we recognized $1.2 million of interest income related to the Note for the three months ended March 31, 2016, of which $1 million was PIK Interest, and we recognized $1.1 million and $3.4 million of interest income related to the Note for the three and nine months ended September 30, 2015, respectively, of which $0.8 million and $2.4 million, respectively, was PIK Interest.
Additionally, during the three months ended March 31, 2016, 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 was not reasonably assured based on the analysis we performed as of March 31, 2016. In August 2016, we collected the $0.7 million promissory note and reversed the related provision and allowance for uncollectible notes receivable during the three months ended September 30, 2016.estimates.
NOTE 4 - PROPERTIES AND EQUIPMENT
The following table presents the components of properties and equipment, net of accumulated depreciation, depletion, and amortization ("DD&A"):
|
| | | | | | | |
| March 31, 2017 | | December 31, 2016 |
| (in thousands) |
Properties and equipment, net: | | | |
Crude oil and natural gas properties | | | |
Proved | $ | 3,675,076 |
| | $ | 3,499,718 |
|
Unproved | 1,874,552 |
| | 1,874,671 |
|
Total crude oil and natural gas properties | 5,549,628 |
| | 5,374,389 |
|
Infrastructure, pipeline, and other | 74,046 |
| | 62,093 |
|
Land and buildings | 14,896 |
| | 12,165 |
|
Construction in progress | 132,776 |
| | 122,591 |
|
Properties and equipment, at cost | 5,771,346 |
| | 5,571,238 |
|
Accumulated DD&A | (1,672,883 | ) | | (1,562,972 | ) |
Properties and equipment, net | $ | 4,098,463 |
| | $ | 4,008,266 |
|
| | | |
The following table presents impairment charges recorded for crude oil and natural gas properties:
|
| | | | | | | |
| Three Months Ended March 31, |
| 2017 | | 2016 |
| (in thousands) |
| | | |
Impairment of proved and unproved properties | $ | 2,102 |
| | $ | 969 |
|
Amortization of individually insignificant unproved properties | 91 |
| | 32 |
|
Total impairment of properties and equipment | $ | 2,193 |
| | $ | 1,001 |
|
NOTE 5 - COMMODITY 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 eachand propane, which is an element of our business segments.
For crude oil and natural gas sales,NGLs, we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity 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; andmarket.
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 commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of September 30, 2016,March 31, 2017, we had derivative instruments, which were comprised of collars, fixed-pricefixed-
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
price swaps, and basis protection swaps, and physical sales and purchases, in place for a portion of our anticipated production through 2018 for a total of 90,42513,912 MBbls of crude oil,75,615 BBtu of natural gas, and 536
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
8,857 MBbls of crude oil. The majority of ourpropane. Our commodity derivative contracts arehave been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices.prices, without adjustment for premium or discount.
We have not elected to designate any of our derivative instruments as cash flow hedges, and therefore these instruments do not qualify for use ofunder hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the condensed consolidated 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.
The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets:
| | | | Fair Value | | Fair Value |
Derivative instruments: | Derivative instruments: | | Condensed Consolidated Balance sheet line item | | September 30, 2016 | | December 31, 2015 | Derivative instruments: | | Condensed consolidated balance sheet line item | | March 31, 2017 | | December 31, 2016 |
| | (in thousands) | | (in thousands) |
Derivative assets: | Current | | | | | Current | | | | |
| Commodity contracts | | | | | |
| Related to crude oil and natural gas sales | | Fair value of derivatives | | $ | 65,191 |
| | $ | 221,161 |
| |
| Related to natural gas marketing | | Fair value of derivatives | | 270 |
| | 441 |
| |
| Basis protection contracts | | | | | |
| Related to crude oil and natural gas sales | | Fair value of derivatives | | 143 |
| | 57 |
| |
| | 65,604 |
| | 221,659 |
| |
| Non-current | | | | | Commodity derivative contracts | | Fair value of derivatives | | $ | 24,437 |
| | $ | 8,490 |
|
| Commodity contracts | | | | | Basis protection derivative contracts | | Fair value of derivatives | | 2,610 |
| | 301 |
|
| Related to crude oil and natural gas sales | | Fair value of derivatives | | 8,122 |
| | 44,292 |
| | 27,047 |
| | 8,791 |
|
| Related to natural gas marketing | | Fair value of derivatives | | 20 |
| | 51 |
| Non-current | | | | |
| Basis protection contracts | | | | | Commodity derivative contracts | | Fair value of derivatives | | 11,279 |
| | 1,123 |
|
| Related to crude oil and natural gas sales | | Fair value of derivatives | | 281 |
| | 44 |
| Basis protection derivative contracts | | Fair value of derivatives | | 2,642 |
| | 1,263 |
|
| | 8,423 |
| | 44,387 |
| | 13,921 |
| | 2,386 |
|
Total derivative assets | | $ | 74,027 |
| | $ | 266,046 |
| Total derivative assets | | $ | 40,968 |
| | $ | 11,177 |
|
| | | | | | | | |
Derivative liabilities: | Current | | | | | Current | | | | |
| Commodity contracts | | | | | Commodity derivative contracts | | Fair value of derivatives | | $ | 26,489 |
| | $ | 53,565 |
|
| Related to crude oil and natural gas sales | | Fair value of derivatives | | $ | 21,639 |
| | $ | — |
| Basis protection derivative contracts | | Fair value of derivatives | | 6 |
| | 30 |
|
| Related to natural gas marketing | | Fair value of derivatives | | 221 |
| | 417 |
| | 26,495 |
| | 53,595 |
|
| Basis protection contracts | | | | | Non-current | | | | |
| Related to crude oil and natural gas sales | | Fair value of derivatives | | 703 |
| | 1,178 |
| Commodity derivative contracts | | Fair value of derivatives | | 4,302 |
| | 27,595 |
|
| | 22,563 |
| | 1,595 |
| | 4,302 |
| | 27,595 |
|
| Non-current | | | | | |
| Commodity contracts | | | | | |
| Related to crude oil and natural gas sales | | Fair value of derivatives | | 17,698 |
| | 275 |
| |
| Related to natural gas marketing | | Fair value of derivatives | | 9 |
| | 46 |
| |
| Basis protection contracts | | | | | |
| Related to crude oil and natural gas sales | | Fair value of derivatives | | 178 |
| | 374 |
| |
| | 17,885 |
| | 695 |
| |
Total derivative liabilities | | $ | 40,448 |
| | $ | 2,290 |
| Total derivative liabilities | | $ | 30,797 |
| | $ | 81,190 |
|
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, |
Condensed consolidated statement of operations line item | | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 |
| | (in thousands) | | (in thousands) |
Commodity price risk management gain (loss), net | | | | | | | | | |
Commodity price risk management gain, net | | | | | |
Net settlements | | $ | 47,728 |
| | $ | 67,993 |
| | $ | 167,859 |
| | $ | 162,454 |
| | $ | 551 |
| | $ | 66,831 |
|
Net change in fair value of unsettled derivatives | | (28,331 | ) | | 55,556 |
| | (230,207 | ) | | (21,284 | ) | | 80,153 |
| | (55,775 | ) |
Total commodity price risk management gain (loss), net | | $ | 19,397 |
| | $ | 123,549 |
| | $ | (62,348 | ) | | $ | 141,170 |
| |
Sales from natural gas marketing | | | | | | | | | |
Net settlements | | $ | 122 |
| | $ | 165 |
| | $ | 420 |
| | $ | 561 |
| |
Net change in fair value of unsettled derivatives | | 255 |
| | (5 | ) | | (263 | ) | | (298 | ) | |
Total sales from natural gas marketing | | $ | 377 |
| | $ | 160 |
| | $ | 157 |
| | $ | 263 |
| |
Cost of natural gas marketing | | | | | | | | | |
Net settlements | | $ | (103 | ) | | $ | (157 | ) | | $ | (380 | ) | | $ | (531 | ) | |
Net change in fair value of unsettled derivatives | | (277 | ) | | (5 | ) | | 293 |
| | 260 |
| |
Total cost of natural gas marketing | | $ | (380 | ) | | $ | (162 | ) | | $ | (87 | ) | | $ | (271 | ) | |
Total commodity price risk management gain, net | | | $ | 80,704 |
| | $ | 11,056 |
|
| | | | | | | | | | | | |
Net settlements of commodity derivatives decreased significantly for the three months ended March 31, 2017, as compared to the three months ended March 31, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior to commodity prices becoming depressed in late 2014. Substantially all of these agreements settled by the end of 2016. Net settlements for the three months ended March 31, 2017 reflect derivative instruments entered into since mid-2014 which approximate recent realized prices. Based upon the forward strip pricing at March 31, 2017, we expect that settlements will be substantially lower on a relative basis as compared to periods in 2016.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
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 September 30, 2016 | | Derivative instruments, recorded in condensed consolidated balance sheet, gross | | Effect of master netting agreements | | Derivative instruments, net | |
As of March 31, 2017 | | | Derivative instruments, recorded in condensed consolidated balance sheet, gross | | Effect of master netting agreements | | Derivative instruments, net |
| | (in thousands) | | (in thousands) |
Asset derivatives: | | | | | | | | | | | | |
Derivative instruments, at fair value | | $ | 74,027 |
| | $ | (22,520 | ) | | $ | 51,507 |
| | $ | 40,968 |
| | $ | (22,720 | ) | | $ | 18,248 |
|
| | | | | | | | | | | | |
Liability derivatives: | | | | | | | | | | | | |
Derivative instruments, at fair value | | $ | 40,448 |
| | $ | (22,520 | ) | | $ | 17,928 |
| | $ | 30,797 |
| | $ | (22,720 | ) | | $ | 8,077 |
|
| | | | | | | | | | | | |
| | As of December 31, 2015 | | Derivative instruments, recorded in condensed consolidated balance sheet, gross | | Effect of master netting agreements | | Derivative instruments, net | |
As of December 31, 2016 | | | Derivative instruments, recorded in condensed consolidated balance sheet, gross | | Effect of master netting agreements | | Derivative instruments, net |
| | (in thousands) | | (in thousands) |
Asset derivatives: | | | | | | | | | | | | |
Derivative instruments, at fair value | | $ | 266,046 |
| | $ | (1,921 | ) | | $ | 264,125 |
| | $ | 11,177 |
| | $ | (10,930 | ) | | $ | 247 |
|
| | | | | | | | | | | | |
Liability derivatives: | | | | | | | | | | | | |
Derivative instruments, at fair value | | $ | 2,290 |
| | $ | (1,921 | ) | | $ | 369 |
| | $ | 81,190 |
| | $ | (10,930 | ) | | $ | 70,260 |
|
| | | | | | | | | | | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
NOTE 56 - PROPERTIES AND EQUIPMENTFAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the componentsDetermination of properties and equipment, net of accumulated depreciation, depletion and amortization ("DD&A"):Fair Value
|
| | | | | | | |
| September 30, 2016 | | December 31, 2015 |
| (in thousands) |
Properties and equipment, net: | | | |
Crude oil and natural gas properties | | | |
Proved | $ | 3,183,772 |
| | $ | 2,881,189 |
|
Unproved | 61,838 |
| | 60,498 |
|
Total crude oil and natural gas properties | 3,245,610 |
| | 2,941,687 |
|
Equipment and other | 31,410 |
| | 30,098 |
|
Land and buildings | 10,900 |
| | 12,667 |
|
Construction in progress | 107,794 |
| | 113,115 |
|
Properties and equipment, at cost | 3,395,714 |
| | 3,097,567 |
|
Accumulated DD&A | (1,463,440 | ) | | (1,157,015 | ) |
Properties and equipment, net | $ | 1,932,274 |
| | $ | 1,940,552 |
|
| | | |
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:
In September 2016, we closed on an acreage exchange transaction with Noble Energy, Inc.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 certaininputs 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 its subsidiaries ("Noble")our derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, consolidate certain acreage positions in the core areacontractual price of the Wattenberg Field. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties.
The following table presents impairment charges recorded forunderlying position, current market prices, crude oil and natural gas properties:forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors,
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) |
| | | | | | | |
Impairment of proved and unproved properties | $ | 338 |
| | $ | 150,840 |
| | $ | 2,391 |
| | $ | 152,764 |
|
Amortization of individually insignificant unproved properties | 595 |
| | 3,191 |
| | 681 |
| | 8,443 |
|
Impairment of crude oil and natural gas properties
| 933 |
| | 154,031 |
| | 3,072 |
| | 161,207 |
|
Land and buildings | — |
| | — |
| | 3,032 |
| | — |
|
Impairment of properties and equipment | $ | 933 |
| | $ | 154,031 |
| | $ | 6,104 |
| | $ | 161,207 |
|
NOTE 6 - PENDING ACQUISITION
In August 2016, we entered into acquisition agreements to purchase Arris Petroleum Corporation (“Arris”) and the assets of 299 Resources, LLC, 299 Production, LLC and 299 Pipeline, LLC (collectively, “299 Sellers”) pursuant to which, and subject to the terms and conditions of those agreements, we have agreed to acquire an aggregate of approximately 57,000 net acres, approximately 30 wells and other related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to Arris and 299 Sellers of approximately $915 million in cash and approximately 9.4 million shares of our common stock (valued at approximately $590 million at the time the acquisition agreements were executed), subject to certain adjustments, and ongoing due diligence (the "Delaware Basin Acquisition"). The acquisition agreements allow the sellers to include a specified amount of additional leases in the transaction, which would increase the purchase price. Upon executing the acquisition agreements, we paid a $100 million deposit toward the cash portion of the purchase price into an escrow account, which is included in other assets in our September 30, 2016 condensed consolidated balance sheet. In some circumstances set forth in the acquisition agreements, we could be required to forfeit the $100 million deposit. The acquisition is expected to close in December 2016; however, there can be no assurance that conditions to closing will be satisfied.
In order to fund the cash portion of the Delaware Basin Acquisition, we completed a public offering of shares of our common stock, a public offering of convertible senior notes and a private offering of senior notes in September 2016. See Note 8, Long-Term Debt, and Note 12, Common Stock, for further information. Prior to the September 2016 issuances of common stock, convertible senior notes and senior notes, we entered into a commitment letter with JPMorgan Chase Bank, N.A. (“JPMorgan”), for short-term bridge financing of the Delaware Basin Acquisition. The commitment letter contemplated, among other things, (i) a senior unsecured bridge loan to us in an aggregate principal amount not to exceed $600 million, to be drawn, if at all, at the closing of the Delaware Basin Acquisition, (ii) a $250 million increase in the commitments under our existing revolving credit facility and (iii) certain related proposed amendments and waivers to our existing credit facility agreement. Upon issuance of the common stock, convertible senior notes and senior notes, the bridge loan commitment was terminated. Upon closing of
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016March 31, 2017
(unaudited)
and nonperformance risk. Nonperformance risk considers the Delaware Basin Acquisition,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 basis swaps and crude oil and natural gas fixed-price swaps are included in Level 2 and our collars, physical sales, and propane fixed-price swaps 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, 2017 | | December 31, 2016 |
| 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: | | | | | | | | | | | |
Total assets | $ | 33,483 |
| | $ | 7,485 |
| | $ | 40,968 |
| | $ | 6,350 |
| | $ | 4,827 |
| | $ | 11,177 |
|
Total liabilities | (25,628 | ) | | (5,169 | ) | | (30,797 | ) | | (66,789 | ) | | (14,401 | ) | | (81,190 | ) |
Net asset (liability) | $ | 7,855 |
| | $ | 2,316 |
| | $ | 10,171 |
| | $ | (60,439 | ) | | $ | (9,574 | ) | | $ | (70,013 | ) |
| | | | | | | | | | | |
The following table presents a reconciliation of our Level 3 assets measured at fair value:
|
| | | | | | | | |
| | Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in thousands) |
Fair value of Level 3 instruments, net asset (liability) beginning of period | | $ | (9,574 | ) | | $ | 91,288 |
|
Changes in fair value included in condensed consolidated statement of operations line item: | | | | |
Commodity price risk management gain, net | | 13,360 |
| | 6,165 |
|
Settlements included in statement of operations line items: | | | | |
Commodity price risk management gain, net | | (1,470 | ) | | (24,258 | ) |
Fair value of Level 3 instruments, net asset end of period | | $ | 2,316 |
| | $ | 73,195 |
|
| | | | |
Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item: | | | | |
Commodity price risk management gain, net | | $ | 11,427 |
| | $ | 4,185 |
|
| | | | |
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 during the periods covered by this report.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
Short-term Investments
We categorize our short-term investments as held-to-maturity as we have the positive intent and ability to hold the securities to maturity. We have invested in commercial paper with entities with financial ratings in the A1/P1 category. At March 31, 2017, all of our held-to-maturity securities had maturities within one year of the balance sheet date and we did not realize any losses. Short-term investments in marketable securities potentially subject us to a concentration of credit risk as substantially all of our debt securities are held with one counterparty. We hold our marketable securities with major corporations with high credit standings. The carrying value of our short-term investments approximates fair value due to the short-term maturities of these investments. The amortized cost of our held-to-maturity securities at March 31, 2017 was $49.9 million. We did not hold any short-term investments at December 31, 2016.
Non-Derivative Financial Assets and Liabilities
The carrying value of the financial instruments included in current assets and current liabilities 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 and goodwill for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. 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 required to pay approximately $9 millionsold. The fair value of the goodwill is determined using either a qualitative method or a quantitative method, both of which utilize market data, a Level 2 input, in feesthe derivation of the value estimation.
The portion of our long-term debt related to the bridge loan commitment, approximately $6 million in fees related to the increase in commitments under theour 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, we have determined an estimate of the fair values based on measurements of trading activity and approximately $10 million inbroker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of March 31, 2017.
|
| | | | | | | |
| | Estimated Fair Value | | Percent of Par |
| | (in millions) | | |
Senior notes: | | | |
| 2021 Convertible Notes | $ | 206.0 |
| | 103.0 | % |
| 2022 Senior Notes | 530.0 |
| | 106.0 | % |
| 2024 Senior Notes | 416.0 |
| | 104.0 | % |
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 related vehicle lease.
Concentration of Risk
Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our commodity derivative contracts; however, an insignificant portion of our commodity derivative instruments may be with other direct acquisition-related costs. Duringcounterparties. To date, we have had no derivative counterparty default losses. 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 current counterparties on the fair value of our derivative instruments is not significant at March 31, 2017, taking into account the estimated likelihood of nonperformance.
Cash and Cash Equivalents. We consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
substantially all of our deposits held in financial institutions were in excess of the FDIC insurance limits at March 31, 2017. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy, and are also major lenders under our revolving credit facility.
Notes Receivable. In October 2014, we sold our entire 50 percent ownership interest in PDCM to an unrelated third-party. As part of the consideration, we received a promissory note (the “Promissory Note”) for a principal sum of $39.0 million, bearing varying interest rates. The interest was to be paid quarterly, in arrears and at the option of the issuer, could be paid-in-kind (“PIK Interest”) and any such PIK Interest would be subject to the then current interest rate.
We regularly analyze the Promissory Note for evidence of collectability, evaluating factors such as the creditworthiness of the issuer of the Promissory Note and the value of the underlying assets that secure the Promissory Note. Based upon this analysis, during the quarter ended September 30,March 31, 2016, we recognized a provision and recorded chargesan allowance for uncollectible notes receivable for the bridge loan fees$44.0 million accumulated outstanding balance, including interest. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Promissory Note and began accounting for the interest on the Promissory Note under the cash basis method.
We performed this analysis as of March 31, 2017 and, based upon the evaluation of preliminary 2016 year-end financial statements and related information of the issuer and existing market conditions for natural gas, it was determined that collection of the Promissory Note and PIK Interest continued to be doubtful and the other direct acquisition-related costs. The $9 million charge for fees related tofull valuation allowance on the bridge loan commitment is included in interest expense and the $10 million charge for other direct acquisition-related costs is included in general and administrative expenses. The liabilities associated with both amounts are included in other accrued expenses on our condensed consolidated balance sheetPromissory Note remained appropriate as of September 30, 2016.that date. This evaluation assumed repayment of the Promissory Note would be satisfied exclusively from the existing operations of the issuer of the Promissory Note based on the latest available information.
At the end of April 2017, PDC entered into an agreement to sell the Promissory Note to an unrelated third-party buyer. Such agreement transferred all of the Company’s legal right to collect from the issuer of the Promissory Note. The sale of the Promissory Note was for cash consideration of approximately $40.3 million. The transaction closed and all funds were collected simultaneously on the date the definitive agreement to sell the Promissory Note was signed. As an agreement to sell the Promissory Note was not in effect and did not exist at March 31, 2017, this transaction has been deemed to be a subsequent event to be recorded in the second quarter of 2017. Accordingly, the Company reversed $40.3 million of the provision for uncollectible notes receivable in April 2017.
NOTE 7 - 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 annual 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 and nine months ended September 30, 2016March 31, 2017, was a 34.0% and 37.1% benefit36.3 percent expense on lossincome compared to a 33.8% and 36.3%36.9 percent benefit on loss for the three and nine months ended September 30, 2015.March 31, 2016. The effective tax rate for the three and nine months ended September 30,March 31, 2017, includes discrete tax benefits of $1.6 million relating to the excess tax basis recognized with the vesting of stock awards during the three months ended March 31, 2017, which resulted in a 2.2 percent reduction to our effective tax rate.
The effective tax rate for the three months ended March 31, 2017, is based upon a full year forecasted tax provision on income and is greater than the statutory federal tax rate, primarily due to state taxes, nondeductible officers’ compensation and nondeductible lobbying expenses, partially offset by stock-based compensation tax deductions. We anticipate the potential for increased periodic volatility in future effective tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items. The effective tax rate for the three months ended March 31, 2016 iswas 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 and nine months ended September 30, 2015 differs from the statutory rate primarily due to state taxes and percentage depletion, partially offset by nondeductible officers' compensation. There were no significant discrete tax items recorded during the three and nine months ended September 30, 2016 or September 30, 2015.March 31, 2016.
As of September 30, 2016,March 31, 2017, there is no liability for unrecognized tax benefits. 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 to voluntarily participate in the Internal Revenue Service's ("IRS") Compliance Assurance Program ("CAP") for the 20152016 and 2016 tax years. With respect to the 2014 tax year, we have agreed to a post filing adjustment with the IRS which resulted in an immaterial tax payment for the 2014 tax year. The IRS has fully accepted the 2014 federal return, as adjusted. The IRS has partially accepted our recently filed 2015 return that is now going through the IRS CAP post-filing review process.2017
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016March 31, 2017
(unaudited)
tax years, and received final acceptance of our 2015 federal income tax return and closure of the 2015 tax year during the three months ended March 31, 2017.
NOTE 8 - LONG-TERM DEBT
Long-term debt consisted of the following as of:
| | | September 30, 2016 | | December 31, 2015 | March 31, 2017 | | December 31, 2016 |
| (in thousands) | (in thousands) |
Senior notes: | | | | | | |
1.125% Convertible senior notes due 2021: | | | | |
1.125% Convertible Notes due 2021: | | | | |
Principal amount | $ | 200,000 |
| | $ | — |
| $ | 200,000 |
| | $ | 200,000 |
|
Unamortized discount | (39,199 | ) | | — |
| (35,727 | ) | | (37,475 | ) |
Unamortized debt issuance costs | (4,793 | ) | | — |
| (4,346 | ) | | (4,584 | ) |
1.125% Convertible senior notes due 2021, net of unamortized discount and debt issuance costs | 156,008 |
| | — |
| |
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs | | 159,927 |
| | 157,941 |
|
| | | | | | |
6.125% Senior notes due 2024: | | | | |
7.75% Senior Notes due 2022: | | | | |
Principal amount | 400,000 |
| | — |
| 500,000 |
| | 500,000 |
|
Unamortized debt issuance costs | (7,710 | ) | | — |
| (6,162 | ) | | (6,443 | ) |
6.125% Senior notes due 2024, net of unamortized debt issuance costs | 392,290 |
| | — |
| |
7.75% Senior Notes due 2022, net of unamortized debt issuance costs | | 493,838 |
| | 493,557 |
|
| | | | | | |
7.75% Senior notes due 2022: | | | | |
6.125% Senior Notes due 2024: | | | | |
Principal amount | 500,000 |
| | 500,000 |
| 400,000 |
| | 400,000 |
|
Unamortized debt issuance costs | (6,723 | ) | | (7,563 | ) | (7,304 | ) | | (7,544 | ) |
7.75% Senior notes due 2022, net of unamortized debt issuance costs | 493,277 |
| | 492,437 |
| |
6.125% Senior Notes due 2024, net of unamortized debt issuance costs | | 392,696 |
| | 392,456 |
|
| | | | | | |
3.25% Convertible senior notes due 2016: | | | | |
Principal amount | — |
| | 115,000 |
| |
Unamortized discount | — |
| | (1,852 | ) | |
Unamortized debt issuance costs | — |
| | (208 | ) | |
3.25% Convertible senior notes due 2016, net of unamortized discount and debt issuance costs | — |
| | 112,940 |
| |
Total senior notes | 1,041,575 |
| | 605,377 |
| 1,046,461 |
| | 1,043,954 |
|
| | | | | | |
Revolving credit facility | — |
| | 37,000 |
| — |
| | — |
|
Total debt, net of unamortized discount and debt issuance costs | 1,041,575 |
| | 642,377 |
| |
Less current portion of long-term debt | — |
| | 112,940 |
| |
Long-term debt | $ | 1,041,575 |
| | $ | 529,437 |
| |
Total long-term debt, net of unamortized discount and debt issuance costs | | $ | 1,046,461 |
| | $ | 1,043,954 |
|
Senior Notes
1.125%2021 Convertible Senior Notes Due 2021.Notes. In September 2016, we issued $200$200.0 million of 1.125% convertible senior notes due 2021 (the "2021 Convertible Notes") in a public offering. The 2021 Convertible Notes are governed by an indenture dated September 14, 2016 between us and the U.S. Bank National Association, as trustee. The maturity for the payment of principal is September 15, 2021. Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15, commencing on March 15, 2017. The conversion stock price at maturity is $85.39 per share. We allocated the gross proceeds of the 2021 Convertible Notes are senior unsecured obligationsbetween the liability and rank senior in rightequity components of payment to our future indebtedness that is expressly subordinated tothe debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments excluding the conversion feature for similar terms and priced on the same day we issued the 2021 Convertible Notes; equalNotes. Approximately $4.8 million in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. The proceeds fromcosts associated with the issuance of the 2021 Convertible Notes, after deducting offering expenses and underwriting discounts, are expectedNote have been capitalized as debt issuance costs. As of March 31, 2017, the unamortized debt discount will be amortized over the remaining contractual term to be used to fund a portion of the purchase price of the Delaware Basin Acquisition (see Note 6, Pending Acquisition), to pay related fees and expenses and for general corporate purposes.
The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, in each case at an initial conversion rate of 11.7113 per $1,000 principal amountmaturity of the 2021 Convertible Notes which is equal tousing an initial conversion priceeffective interest rate of approximately $85.39 per share. The conversion rate is subject to adjustment upon certain events. Upon5.8 percent.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash, or a combination of cash and shares of our common stock. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares.
We may not redeem the 2021 Convertible Notes prior to their maturity date. If2022 Senior Notes. In October 2012, we undergo a fundamental change, as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100% of theissued $500.0 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”). The 2022 Senior Notes accrue interest from the date of the 2021 Convertible Notes to be repurchased, plus any accruedissuance and unpaid interest to, but excluding, the fundamental change repurchase date. The occurrence of a fundamental change will also resultis payable semi-annually in the 2021 Convertible Notes becoming convertible.
We allocated the gross proceeds of the 2021 Convertible Notes between the liabilityarrears on April 15 and equity components of the debt. The initial $160.5 million million liability component was determined based on the fair value of similar debt instruments excluding the conversion feature for similar terms and priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes.October 15. Approximately $4.8$11.0 million in costs associated with the
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
issuance of the 2021 Convertible2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. As of September 30, 2016, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using an effective interest rate of 5.8%. Based upon a September 30, 2016 stock price of $67.06 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount.
6.125%2024 Senior Notes Due 2024.Notes. In September 2016, we issued $400$400.0 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”) in a private placement. The proceeds from the issuance of the 2024 Senior Notes, after deducting offering expenses and underwriting discounts, are expectedplacement to be used to fund a portion of the purchase price of the Delaware Basin Acquisition (see Note 6, Pending Acquisition), to pay related fees and expenses and for general corporate purposes. If the acquisition is not completed on or prior to December 31, 2016 (or in some circumstances by or on January 15, 2017), the 2024 Senior Notes will be redeemed in whole at a special mandatory redemption price equal to 100% of the aggregate principal amount of the 2024 notes, plus accrued and unpaid interest.
qualified institutional buyers. The 2024 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on March 15 and September 15, commencing on March 15, 2017. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2024
In January 2017, pursuant to the filing of supplemental indentures for the 2021 Convertible Notes, 2022 Senior Notes, are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.
In connection with the issuance of the 2024 Senior Notes we entered into(the "Notes"), our wholly-owned subsidiary, PDC Permian, Inc., became a registration rights agreement withguarantor of our obligations under the initial purchasers in which we agreed to file a registration statement with the SEC relating to an offer to exchange the 2024 Senior NotesNotes. Accordingly, condensed consolidating financial information for registered notes with substantially identical terms. In addition, we have agreed, in certain circumstances, to file a shelf registration statement covering the resale of the 2024 Senior Notes by holders.
At any time prior to September 15, 2019, we may redeem up to 35% of the outstanding 2024 Senior Notes with proceeds from certain equity offerings at a redemption price of 106.125% of the principal amount of the notes redeemed, plus accruedPDC and unpaid interest, if at least 65% of the aggregate principal amount of the 2024 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering.
Upon the occurrence of a "change of control," as definedPDC Permian, Inc. is presented in the indenture for the 2024 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100% of the principal amount, together with any accrued and unpaid interest to the date of purchase.
The indenture governing the 2024 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries.
7.75% Senior Notes Due 2022.footnote titled In October 2012, we issued $500 million aggregate principal amount of 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”) in a private placement. The 2022 Senior Notes accrue interest from the date of issuance and interest
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
is payable semi-annually in arrears on April 15 and October 15. The indenture governing the 2022 Senior Notes contains customary restrictive incurrence covenants, and customary repurchase and redemption provisions, generally similar to those in the indenture governing the 2024 Senior Notes. Capitalized debt issuance costs are being amortized as interest expense over the life of the 2022 Senior Notes using the effective interest method.
3.25% Convertible Senior Notes Due 2016Subsidiary Guarantor. In November 2010, we issued $115 million aggregate principal amount of 3.25% convertible senior notes due 2016 (the "2016 Convertible Notes") in a private placement. The maturity for the payment of principal was May 15, 2016. At December 31, 2015, our indebtedness included the 2016 Convertible Notes. Upon settlement in May 2016, we paid the aggregate principal amount of the 2016 Convertible Notes, plus cash for fractional shares, totaling approximately 115 million, utilizing proceeds from our March 2016 equity offering. Additionally, we issued 792,406 shares of common stock for the $47.9 million excess conversion value. See Note 12, Common Stock, for more information.
As of September 30, 2016,March 31, 2017, we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Senior Notes and 2022 Senior Notes, and expect to remain in compliance throughout the next 12-month period.
Revolving 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 and is available for working capital requirements, capital expenditures,investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility matures in May 2020, and provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base which is currently $700 million, and the aggregate commitments, which are currently $450 million.certain limitations under our senior notes. The borrowing base amount available under the revolving credit facility 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.interests. The borrowing base is subject to a semi-annual size redetermination on November 1 and May 1 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 substantially alla pledge of the stock of certain of our assets, includingsubsidiaries, mortgages of certain producing crude oil and natural gas properties.properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility.
In September 2016, we entered into a Third Amendment to the Third Amended The current borrowing base and Restated Credit Agreement. The amendment, among other things, amends the revolving credit facility to permit the completion of the Delaware Basin Acquisition (see Note 6, Pending Acquisition) and, effective upon closing of the acquisition, adjusts the interest rate payable on amounts borrowed under the facility and increases the aggregate commitments under the facility from $450 millionare $700 million. The May 1, 2017 redetermination has not been finalized as of the date of this report.
As of March 31, 2017 and December 31, 2016, debt issuance costs related to $700 million (with the borrowing base remaining at $700 million).
In October 2016, we entered into a Fourth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, reaffirmed of our borrowing base at $700revolving credit facility were $8.1 million and made certain$8.8 million, respectively, and are included in other immaterial modifications toassets on the existing agreement, including an increase in the amount of our future production that we are permitted to hedge.
condensed consolidated balance sheets. We had no outstanding balance on our revolving credit facility as of September 30, 2016, compared to $37 million outstanding as ofMarch 31, 2017 or December 31, 2015.2016. The weighted-average interest rate onoutstanding principal amount under the outstanding balance on our revolving credit facility exclusiveaccrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium), or at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, oninterest margin, and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of March 31, 2017, the applicable interest margin is 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment andfee is 0.50 percent. No principal payments are generally required until the letter of credit noted below, was 2.6% per annum as of December 31, 2015.
As of September 30, 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 is currently scheduled to expire in September 2017 but is expected to be 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 toexpires in May 2020, or in the letter of credit. As of September 30, 2016,event that the available funds under our revolving credit facility, includingborrowing base falls below the reduction for the $11.7 million letter of credit, was $438.3 million.outstanding balance.
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, as of September 30, 2016, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.001.0:1.0 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00. 4.0:1.0. As of September 30, 2016,March 31, 2017, we were in compliance with all of the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. Effective upon closing ofAs defined by the Delaware Basin Acquisition, the maximum permittedrevolving credit facility, our current ratio was 3.7and our leverage ratio will be reducedwas 2.0as of March 31, 2017.
As of March 31, 2017, we had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to 4.00 to 1.00.secure a firm transportation obligation. As of March 31, 2017, the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $688.3 million.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016March 31, 2017
(unaudited)
NOTE 9 - OTHER ACCRUED EXPENSES
Other Accrued Expenses. The following table presents the components of other accrued expenses:
|
| | | | | | | |
| March 31, 2017 | | December 31, 2016 |
| (in thousands) |
| | | |
Employee benefits | $ | 7,659 |
| | $ | 22,282 |
|
Asset retirement obligations | 12,937 |
| | 9,775 |
|
Environmental expenses | 4,624 |
| | 4,438 |
|
Other | 1,718 |
| | 2,130 |
|
Other accrued expenses | $ | 26,938 |
| | $ | 38,625 |
|
| | | |
NOTE 10 - CAPITAL LEASES
We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90%90 percent of the fair value of the leased vehicles at inception of the lease.
The following table presents leased vehicles under capital leaseslease as of September 30, 2016:March 31, 2017:
| |
| | Amount | | March 31, 2017 | | December 31, 2016 |
| | (in thousands) | | (in thousands) |
Vehicles | | $ | 2,801 |
| | $ | 4,126 |
| | $ | 2,975 |
|
Accumulated depreciation | | (613 | ) | | (973 | ) | | (776 | ) |
| | $ | 2,188 |
| | $ | 3,153 |
| | $ | 2,199 |
|
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 September 30, | | Amount | |
For the Twelve Months Ending March 31, | | | Amount |
| | (in thousands) | | (in thousands) |
2017 | | $ | 860 |
| |
2018 | | 1,167 |
| | $ | 1,413 |
|
2019 | | 553 |
| | 1,376 |
|
2020 | | | 946 |
|
| | 2,580 |
| | 3,735 |
|
Less executory cost | | (101 | ) | | (155 | ) |
Less amount representing interest | | (280 | ) | | (402 | ) |
Present value of minimum lease payments | | $ | 2,199 |
| | $ | 3,178 |
|
| | |
| | |
|
Short-term capital lease obligations | | $ | 646 |
| | $ | 1,108 |
|
Long-term capital lease obligations | | 1,553 |
| | 2,070 |
|
| | $ | 2,199 |
| | $ | 3,178 |
|
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.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
NOTE 1011 - 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 | Amount |
| (in thousands) | (in thousands) |
| | |
Balance at beginning of period, January 1, 2016 | $ | 89,492 |
| |
Balance at beginning of period, January 1, 2017 | | $ | 92,387 |
|
Obligations incurred with development activities | 1,137 |
| 1,232 |
|
Accretion expense | 5,400 |
| 1,768 |
|
Obligations discharged with disposal of properties and asset retirements | (6,620 | ) | |
Balance end of period, September 30, 2016 | 89,409 |
| |
Obligations discharged with asset retirements | | (4,288 | ) |
Balance at end of period, March 31, 2017 | | 91,099 |
|
Less current portion | (6,900 | ) | (12,937 | ) |
Long-term portion | $ | 82,509 |
| $ | 78,162 |
|
| | |
Our estimated asset retirement obligationobligations 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 2016,As of March 31, 2017, the credit-adjusted risk-free
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
rates used to discount our plugging and abandonment liabilities ranged from 7.6%6.5 percent to 8.0%.8.2 percent. 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 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 1112 - 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, royalty, and overriding royalty interest owners. We record in our financialowners whose volumes we market on their behalf. Our statements onlyof operations reflect our share of costs based upon our working interest in the wells.these firm transportation costs. 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 September 30, 2016, we have recorded an allowance for doubtful accounts of approximately $1.1 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.
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 September 30, | | | | | For the Twelve Months Ending March 31, | | | |
Area | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 and Through Expiration | | Total | | Expiration Date | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 and Through Expiration | | Total | | Expiration Date |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas (MMcf) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gas Marketing segment | | 7,117 |
| | 7,117 |
| | 7,117 |
| | 7,136 |
| | 13,344 |
| | 41,831 |
| | August 31, 2022 | |
Wattenberg Field | | | — |
| | 5,845 |
| | 18,849 |
| | 18,798 |
| | 84,666 |
| | 128,158 |
| | September 30, 2025 |
Delaware Basin | | | 13,400 |
| | 14,600 |
| | 14,640 |
| | 11,000 |
| | — |
| | 53,640 |
| | December 31, 2020 |
Gas Marketing | | | 7,117 |
| | 7,117 |
| | 7,136 |
| | 7,117 |
| | 9,796 |
| | 38,283 |
| | August 31, 2022 |
Utica Shale | | 2,738 |
| | 2,738 |
| | 2,738 |
| | 2,745 |
| | 7,754 |
| | 18,713 |
| | July 22, 2023 | | 2,737 |
| | 2,737 |
| | 2,745 |
| | 2,737 |
| | 6,391 |
| | 17,347 |
| | July 22, 2023 |
Total | | 9,855 |
| | 9,855 |
| | 9,855 |
| | 9,881 |
| | 21,098 |
| | 60,544 |
| | | 23,254 |
| | 30,299 |
| | 43,370 |
| | 39,652 |
| | 100,853 |
| | 237,428 |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Crude oil (MBbls) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | 2,413 |
| | 2,413 |
| | 2,413 |
| | 1,813 |
| | — |
| | 9,052 |
| | June 30, 2020 | | 2,413 |
| | 2,413 |
| | 2,420 |
| | 602 |
| | — |
| | 7,848 |
| | June 30, 2020 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Dollar commitment (in thousands) | | $ | 17,470 |
| | $ | 16,324 |
| | $ | 16,324 |
| | $ | 13,205 |
| | $ | 8,102 |
| | $ | 71,425 |
| | | $ | 18,726 |
| | $ | 24,216 |
| | $ | 36,799 |
| | $ | 26,211 |
| | $ | 86,280 |
| | $ | 192,232 |
| |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
Litigation. In December 2016, in anticipation of our future drilling activities in the Wattenberg Field, we entered into a facilities expansion agreement with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct a new 200 MMcfd cryogenic plant. We will be bound to the volume requirements in this agreement on the first day of the calendar month after the actual in-service date of the plant, which in the above table is estimated to be September 30, 2018. The agreement requires a baseline volume commitment, consisting of our gross wellhead volume delivered in November 2016, to this midstream provider and an incremental wellhead volume commitment of 51.5 MMcfd for seven years. We may be required to pay a shortfall fee for any volumes under the 51.5 MMcfd incremental commitment. Any shortfall of this volume commitment may be offset, by additional third party producers’ volumes sold to the midstream provider that are greater then a certain total baseline volume. We are also required for the first three years of the contract to guarantee a certain target profit margin to the midstream provider on these incremental volumes. We expect that our development plan will support the utilization of that capacity.
We entered into a transportation service agreement for delivery of 40,000 dekatherms per day of our Delaware Basin natural gas production to the Waha market hub in West Texas. The contract is effective May 1, 2017 and is in effect through December 31, 2020.
For each of the three months ended March 31, 2017 and March 31, 2016, commitments for long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $0.9 million and were recorded in transportation, gathering, and processing expense in our condensed consolidated statements of operations. During the three months ended March 31, 2017 and March 31, 2016, long-term firm transportation costs for our gas marketing business associated with the commitments shown above were $2.2 million and $2.4 million, respectively, and were recorded in other expenses in our condensed consolidated statements of operations.
Litigation and Legal Items. The Company is involved in various legal proceedings that we consider normal to our business. We reviewproceedings. 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 ourthe best interests. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any,interests of the Company. Management has provided the necessary estimated accruals in the remainingaccompanying balance sheets where deemed appropriate for litigation willand legal related items that are ongoing and not exceed the amounts reserved.yet concluded. 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.
A group of 42 independent West Virginia natural gas producers has filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. (“Dominion”), certain entities affiliated with Dominion, and RNG as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. RNG and Dominion have removed the case to the U.S. District Court for the Northern District of West Virginia and are preparing pre-trial pleadings, including an answer to the complaint and a motion to dismiss the case. At this time, RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses.
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 regularperiodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events that require remediation are probable and the costs can be reasonably estimated. As of September 30, 2016 and December 31, 2015,Except as discussed herein, we had accrued environmental liabilities in the amount of $3.2 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 September 30, 2016March 31, 2017 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. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focusedfocuses 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. We continue to meet withIn December 2016, we received a draft consent decree from the EPA and provide additional information, but cannot predict the outcome of this matter at this time.EPA.
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 of volatile organic compounds to the maximum extent possible at 65 facilities consistent with applicable standards under Colorado law. We are workingThis matter has been combined with the agencymatter discussed above. We have ongoing discussions with the EPA, U.S. Department of Justice, and Colorado Department of Public Health and Environment regarding these matters. The ultimate outcome related to address the allegations, but cannot predict the outcome of this matterthese combined actions has not been determined at this time.
Employment Agreements with Executive Officers. Each17
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
NOTE 1213 - COMMON STOCK
Sale of Equity Securities
In September 2016, we completed a public offering of 9,085,000 shares of our common stock at a price to us of $61.51 per share. Net proceeds of the offering were $558.5 million, after deducting offering expenses and underwriting discounts, of which $90,850 is included in common shares-par value and $558.4 million is included in additional paid-in capital ("APIC") on the September 30, 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 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, of which $59,225 is included in common shares-par value and $296.5 million is included in APIC on the September 30, 2016 condensed consolidated balance sheet. The shares were issued pursuant to the 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 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 September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 |
| | (in thousands) | | (in thousands) |
| | | | | | | | | | | | |
Stock-based compensation expense | | $ | 4,079 |
| | $ | 4,813 |
| | $ | 15,205 |
| | $ | 14,278 |
| | $ | 4,453 |
| | $ | 4,682 |
|
Income tax benefit | | (1,552 | ) | | (1,828 | ) | | (5,786 | ) | | (5,423 | ) | | (1,666 | ) | | (1,782 | ) |
Net stock-based compensation expense | | $ | 2,527 |
| | $ | 2,985 |
| | $ | 9,419 |
| | $ | 8,855 |
| | $ | 2,787 |
| | $ | 2,900 |
|
| | | | | | | | | | | | |
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.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
In January 2016, theThe Compensation Committee of our Board of Directors awarded 58,709 SARs to our executive officers.officers during the three months ended March 31, 2017 and 2016. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:
| | | Nine Months Ended September 30, | Three Months Ended March 31, |
| 2016 | | 2015 | 2017 | | 2016 |
| | | | | | |
Expected term of award | 6.0 years |
| | 5.2 years |
| |
Expected term of award (in years) | | 6 |
| | 6 |
|
Risk-free interest rate | 1.8 | % | | 1.4 | % | 2.0 | % | | 1.8 | % |
Expected volatility | 54.5 | % | | 58.0 | % | 53.3 | % | | 54.5 | % |
Weighted-average grant date fair value per share | $ | 26.96 |
| | $ | 22.23 |
| $ | 38.58 |
| | $ | 26.96 |
|
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.
The following table presents the changes in our SARs for all periods presented:the three months ended March 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 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 | (141,084 | ) | | 40.16 |
| | | | $ | 2,770 |
| | — |
| | — |
| | | | |
Outstanding at September 30, | 244,078 |
| | 41.36 |
| | 7.1 | | 6,273 |
| | 347,285 |
| | 38.94 |
| | 7.5 | | $ | 4,888 |
|
Vested and expected to vest at September 30, | 238,671 |
| | 41.20 |
| | 7.1 | | 6,171 |
| | 341,423 |
| | 38.89 |
| | 7.5 | | 4,821 |
|
Exercisable at September 30, | 136,644 |
| | 36.74 |
| | 5.9 | | 4,143 |
| | 191,149 |
| | 35.68 |
| | 6.6 | | 3,312 |
|
|
| | | | | | | | | | | | | |
| Number of SARs | | Weighted-Average Exercise Price | | Average Remaining Contractual Term (in years) | | Aggregate Intrinsic Value (in thousands) |
Outstanding at December 31, 2016 | 244,078 |
| | $ | 41.36 |
| | 6.9 |
| | $ | 7,620 |
|
Awarded | 54,142 |
| | 74.57 |
| | — |
| | — |
|
Outstanding at March 31, 2017 | 298,220 |
| | 47.39 |
| | 7.2 |
| | 5,123 |
|
Exercisable at March 31, 2017 | 186,248 |
| | 39.38 |
| | 6.1 |
| | 4,279 |
|
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
Total compensation cost related to SARs granted net of estimated forfeitures, and not yet recognized in our condensed consolidated statement of operations as of September 30, 2016March 31, 2017, was $1.7$3.2 million. The cost is expected to be recognized over a weighted-average period of 1.92.3 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 ninethree months ended September 30, 2016:March 31, 2017:
|
| | | | | | |
| Shares | | Weighted-Average Grant Date Fair Value |
| | | |
Non-vested at December 31, 2015 | 525,081 |
| | $ | 50.23 |
|
Granted | 269,709 |
| | 57.12 |
|
Vested | (256,976 | ) | | 48.60 |
|
Forfeited | (14,716 | ) | | 55.70 |
|
Non-vested at September 30, 2016 | 523,098 |
| | 54.43 |
|
| | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
|
| | | | | | |
| Shares | | Weighted-Average Grant Date Fair Value |
| | | |
Non-vested at December 31, 2016 | 479,642 |
| | $ | 56.09 |
|
Granted | 106,401 |
| | 73.28 |
|
Vested | (48,656 | ) | | 50.46 |
|
Forfeited | (2,244 | ) | | 72.58 |
|
Non-vested at March 31, 2017 | 535,143 |
| | 59.95 |
|
| | | |
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 Nine Months Ended September 30,
| As of/Three Months Ended March 31,
|
| 2016 | | 2015 | 2017 | | 2016 |
| (in thousands, except per share data) | (in thousands, except per share data) |
| | | | | | |
Total intrinsic value of time-based awards vested | $ | 14,675 |
| | $ | 13,061 |
| $ | 3,602 |
| | $ | 3,072 |
|
Total intrinsic value of time-based awards non-vested | 35,079 |
| | 30,959 |
| 33,366 |
| | 32,687 |
|
Market price per common share as of September 30, | 67.06 |
| | 53.01 |
| |
Market price per common share as of March 31, | | 62.35 |
| | 59.45 |
|
Weighted-average grant date fair value per share | 57.12 |
| | 48.58 |
| 73.28 |
| | 51.74 |
|
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 September 30, 2016March 31, 2017, was $18.7 million.$21.5 million This cost is expected to be recognized over a weighted-average period of 1.92.1 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 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, theThe Compensation Committee of our Board of Directors awarded a total of 24,28028,069 market-based restricted shares to our executive officers.officers during the three months ended March 31, 2017. In addition to continuous employment, the vesting of these shares is contingent on the Company'sour total shareholderstockholder return ("TSR"), which is essentially the Company’sour 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, 20182019, and can result in a payout between 0%0 percent and 200%200 percent of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards was computed using the Monte Carlo pricing model using the following assumptions:
|
| | | | | | | |
| Nine Months Ended September 30, |
| 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 |
| | $ | 66.16 |
|
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
|
| | | | | | | |
| Three Months Ended March 31, |
| 2017 | | 2016 |
| | | |
Expected term of award (in years) | 3 |
| | 3 |
|
Risk-free interest rate | 1.4 | % | | 1.2 | % |
Expected volatility | 51.4 | % | | 52.3 | % |
Weighted-average grant date fair value per share | $ | 94.02 |
| | $ | 72.54 |
|
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 ninethree months ended March 31, 2017:September 30, 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 |
|
Vested (1)
| | (11,283 | ) | | 98.50 |
|
Non-vested at September 30, 2016
| | 84,546 |
| | 61.51 |
|
| | | | |
__________
(1)Vested shares were issued at 200% based on our relative total shareholder return as ranked among the Company's peer group. |
| | | | | | | |
| | Shares
| | Weighted-Average Grant Date Fair Value per Share
|
| | | | |
Non-vested at December 31, 2016
| | 48,420 |
| | $ | 64.97 |
|
Granted
| | 28,069 |
| | 94.02 |
|
Non-vested at March 31, 2017
| | 76,489 |
| | 75.63 |
|
| | | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
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 Nine Months Ended September 30, | As of /Three Months Ended March 31, |
| 2016 | | 2015 | 2017 | | 2016 |
| (in thousands, except per share data) | (in thousands, except per share data) |
| | | | | | |
Total intrinsic value of market-based awards vested | $ | 1,174 |
| | $ | — |
| |
Total intrinsic value of market-based awards non-vested | 5,670 |
| | 5,996 |
| $ | 4,769 |
| | $ | 5,697 |
|
Market price per common share as of September 30, | 67.06 |
| | 53.01 |
| |
Market price per common share as of March 31, | | 62.35 |
| | 59.45 |
|
Weighted-average grant date fair value per share | 72.54 |
| | 66.16 |
| 94.02 |
| | 72.54 |
|
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 September 30, 2016March 31, 2017, was $1.9$3.8 million. This cost is expected to be recognized over a weighted-average period of 1.92.3 years.
Preferred Stock
We are authorized, pursuant to stockholder approval in 2008, to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges, and restrictions as shall be fixed by our Board from time to time. As of March 31, 2017 and December 31, 2016, no preferred shares had been issued.
NOTE 1314 - 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.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
The following table presents a reconciliation of the weighted-average diluted shares outstanding:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| (in thousands) | (in thousands) |
| | | | | | | | | | |
Weighted-average common shares outstanding - basic | 48,839 |
| | 40,085 |
| | 45,741 |
| | 38,837 |
| 65,749 |
| | 41,608 |
|
Dilutive effect of: | | | | |
Restricted stock | | 211 |
| | — |
|
Other equity-based awards | | 157 |
| | — |
|
Weighted-average common shares and equivalents outstanding - diluted | 48,839 |
| | 40,085 |
| | 45,741 |
| | 38,837 |
| 66,117 |
| | 41,608 |
|
| | | | | | | | | | |
We reported a net loss for the three and nine months ended September 30, 2016 and 2015, respectively.March 31, 2016. As a result, our basic and diluted weighted-average common shares outstanding were the same for that period 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 September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| (in thousands) | (in thousands) |
| | | | | | | | | | |
Weighted-average common share equivalents excluded from diluted earnings | | | | | | | | | | |
per share due to their anti-dilutive effect: | | | | | | | | | | |
Restricted stock | 660 |
| | 816 |
| | 705 |
| | 836 |
| 76 |
| | 723 |
|
Convertible notes | — |
| | 468 |
| | 345 |
| | 505 |
| — |
| | 508 |
|
Other equity-based awards | 97 |
| | 95 |
| | 103 |
| | 97 |
| 18 |
| | 100 |
|
Total anti-dilutive common share equivalents | 757 |
| | 1,379 |
| | 1,153 |
| | 1,438 |
| 94 |
| | 1,331 |
|
| | | | | | | | | | |
In September 2016, we issued the 2021 Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 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 $85.39 conversion price during the periods presented.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2016
(unaudited)
In November 2010, we issued the $115.0 million aggregate principal amount of 3.25% convertible senior notes that were due in 2016 ("2016 Convertible Notes,Notes"), which gave 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 2016 Convertible Notes matured in May 2016. See Note 8, Long-Term Debt, for additional information. Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method ifwhen the average market share price exceeded the $42.40 conversion price during the periodperiods presented.
Shares issuable upon conversion of the 2021 Convertible Notes and 2016 Convertible Notes were excluded from the diluted earnings per share calculation for the applicable periods as the effect would be anti-dilutive to our earnings per share.
NOTE 1415 - 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.SUBSIDIARY GUARANTOR
Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all ofsubsidiary PDC Permian, Inc. guarantees 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 properties and equipment, 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 inobligations under our two business segments.
publicly-registered Notes. The following
tables present our segment information:presents the condensed consolidating financial information separately for: |
| |
(i) | PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; |
(ii) | PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our Notes; |
(iii) | Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor, and our other subsidiaries and (b) eliminate the investments in our subsidiaries; |
(iv) | Parent and subsidiaries on a consolidated basis ("Consolidated"). |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) |
Segment revenues: | | | | | | | |
Oil and gas exploration and production | $ | 161,212 |
| | $ | 228,520 |
| | $ | 268,090 |
| | $ | 418,356 |
|
Gas marketing | 2,678 |
| | 2,580 |
| | 6,728 |
| | 8,336 |
|
Total revenues | $ | 163,890 |
| | $ | 231,100 |
| | $ | 274,818 |
| | $ | 426,692 |
|
| | | | | | | |
Segment income (loss) before income taxes: | | | | | | | |
Oil and gas exploration and production | $ | 17,809 |
| | $ | (30,296 | ) | | $ | (134,731 | ) | | $ | (14,134 | ) |
Gas marketing | (414 | ) | | (201 | ) | | (1,067 | ) | | (539 | ) |
Unallocated | (52,736 | ) | | (32,164 | ) | | (166,689 | ) | | (97,189 | ) |
Loss before income taxes | $ | (35,341 | ) | | $ | (62,661 | ) | | $ | (302,487 | ) | | $ | (111,862 | ) |
| | | | | | | |
|
| | | | | | | |
| September 30, 2016 | | December 31, 2015 |
| (in thousands) |
Segment assets: | | | |
Oil and gas exploration and production | $ | 3,390,005 |
| | $ | 2,294,288 |
|
Gas marketing | 3,735 |
| | 4,217 |
|
Unallocated | 23,540 |
| | 72,038 |
|
Total assets | $ | 3,417,280 |
| | $ | 2,370,543 |
|
| | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
The Guarantor is 100% owned by the Parent beginning in December 2016. The Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the condensed consolidating financial information follows the same accounting policies as described in the notes to the condensed consolidated financial statements.
The following condensed consolidating financial statements have been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column.
|
| | | | | | | | | | | | | | | | |
| | Condensed Consolidating Balance Sheets |
| | March 31, 2017 |
| | Parent | | Guarantor | | Eliminations | | Consolidated |
| | (in thousands) |
Assets | | | | | | | | |
Current assets | | $ | 397,276 |
| | $ | 14,495 |
| | $ | — |
| | $ | 411,771 |
|
Properties and equipment, net | | 1,923,981 |
| | 2,174,482 |
| | — |
| | 4,098,463 |
|
Intercompany receivable | | 43,550 |
| | — |
| | (43,550 | ) | | — |
|
Investment in subsidiaries | | 1,765,386 |
| | — |
| | (1,765,386 | ) | | — |
|
Goodwill | | — |
| | 56,058 |
| | — |
| | 56,058 |
|
Noncurrent assets | | 26,653 |
| | 185 |
| | — |
| | 26,838 |
|
Total Assets | | $ | 4,156,846 |
| | $ | 2,245,220 |
| | $ | (1,808,936 | ) | | $ | 4,593,130 |
|
| | | | | | | | |
Liabilities and Stockholders' Equity | | | | | | | | |
Current liabilities | | $ | 266,368 |
| | $ | 51,614 |
| | $ | — |
| | $ | 317,982 |
|
Intercompany payable | | — |
| | 43,550 |
| | (43,550 | ) | | — |
|
Long-term debt | | 1,046,461 |
| | — |
| | — |
| | 1,046,461 |
|
Other noncurrent liabilities | | 172,840 |
| | 384,670 |
| | — |
| | 557,510 |
|
Stockholders' equity | | 2,671,177 |
| | 1,765,386 |
| | (1,765,386 | ) | | 2,671,177 |
|
Total Liabilities and Stockholders' Equity | | $ | 4,156,846 |
| | $ | 2,245,220 |
| | $ | (1,808,936 | ) | | $ | 4,593,130 |
|
|
| | | | | | | | | | | | | | | | |
| | Condensed Consolidating Balance Sheets |
| | December 31, 2016 |
| | Parent | | Guarantor | | Eliminations | | Consolidated |
| | (in thousands) |
Assets | | | | | | | | |
Current assets | | $ | 387,309 |
| | $ | 12,516 |
| | $ | — |
| | $ | 399,825 |
|
Properties and equipment, net | | 1,889,419 |
| | 2,118,847 |
| | — |
| | 4,008,266 |
|
Intercompany receivable | | 9,415 |
| | — |
| | (9,415 | ) | | — |
|
Investment in subsidiaries | | 1,765,092 |
| | — |
| | (1,765,092 | ) | | — |
|
Goodwill | | — |
| | 62,041 |
| | — |
| | 62,041 |
|
Noncurrent assets | | 15,539 |
| | 171 |
| | — |
| | 15,710 |
|
Total Assets | | $ | 4,066,774 |
| | $ | 2,193,575 |
| | $ | (1,774,507 | ) | | $ | 4,485,842 |
|
| | | | | | | | |
Liabilities and Stockholders' Equity | | | | | | | | |
Current liabilities | | $ | 235,121 |
| | $ | 35,457 |
| | $ | — |
| | $ | 270,578 |
|
Intercompany payable | | — |
| | 9,415 |
| | (9,415 | ) | | — |
|
Long-term debt | | 1,043,954 |
| | — |
| | — |
| | 1,043,954 |
|
Other noncurrent liabilities | | 164,945 |
| | 383,611 |
| | — |
| | 548,556 |
|
Stockholders' equity | | 2,622,754 |
| | 1,765,092 |
| | (1,765,092 | ) | | 2,622,754 |
|
Total Liabilities and Stockholders' Equity | | $ | 4,066,774 |
| | $ | 2,193,575 |
| | $ | (1,774,507 | ) | | $ | 4,485,842 |
|
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(unaudited)
|
| | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statements of Operations |
| | Three Months Ended March 31, 2017 |
| | Parent | | Guarantor | | Eliminations | | Consolidated |
| | (in thousands) |
| | | | | | | | |
Operating and other revenues | | $ | 254,740 |
| | $ | 18,967 |
| | $ | — |
| | $ | 273,707 |
|
Operating expenses | | 37,499 |
| | 6,681 |
| | — |
| | 44,180 |
|
General and administrative | | 23,529 |
| | 2,786 |
| | — |
| | 26,315 |
|
Depreciation depletion and amortization | | 101,738 |
| | 7,578 |
| | — |
| | 109,316 |
|
Impairment of properties and equipment | | 604 |
| | 1,589 |
| | — |
| | 2,193 |
|
Interest (expense) income | | (19,357 | ) | | 130 |
| | — |
| | (19,227 | ) |
Income before income taxes | | 72,013 |
| | 463 |
| | — |
| | 72,476 |
|
Income tax expense | | (26,162 | ) | | (168 | ) | | — |
| | (26,330 | ) |
Net income | | $ | 45,851 |
| | $ | 295 |
| | $ | — |
| | $ | 46,146 |
|
|
| | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statements of Cash Flows |
| | Three Months Ended March 31, 2017 |
| | Parent | | Guarantor | | Eliminations | | Consolidated |
| | (in thousands) |
| | | | | | | | |
Cash flows from operating activities | | $ | 131,661 |
| | $ | 7,839 |
| | $ | — |
| | $ | 139,500 |
|
Cash flows from investing activities: | | | | | | | | |
Capital expenditures for development of crude oil and natural properties | | (82,489 | ) | | (47,337 | ) | | — |
| | (129,826 | ) |
Capital expenditures for other properties and equipment | | (890 | ) | | 69 |
| | — |
| | (821 | ) |
Acquisition of crude oil and natural gas properties, including settlement adjustments | | — |
| | 6,181 |
| | — |
| | 6,181 |
|
Proceeds from sale of properties and equipment | | 737 |
| | — |
| | — |
| | 737 |
|
Purchases of short-term investments | | (49,890 | ) | | — |
| | — |
| | (49,890 | ) |
Intercompany transfers | | (33,795 | ) | | — |
| | 33,795 |
| | — |
|
Net cash from investing activities | | (166,327 | ) | | (41,087 | ) | | 33,795 |
| | (173,619 | ) |
Cash flows from financing activities: | | | | | | | | |
Proceeds from issuance of equity, net of issuance costs | | (8 | ) | | — |
| | — |
| | (8 | ) |
Other | | (2,339 | ) | | (10 | ) | | — |
| | (2,349 | ) |
Intercompany transfers | | — |
| | 33,795 |
| | (33,795 | ) | | — |
|
Net cash from financing activities | | (2,347 | ) | | 33,785 |
| | (33,795 | ) | | (2,357 | ) |
Net change in cash and cash equivalents | | (37,013 | ) | | 537 |
| | — |
| | (36,476 | ) |
Cash and cash equivalents, beginning of period | | 240,487 |
| | 3,613 |
| | — |
| | 244,100 |
|
Cash and cash equivalents, end of period | | $ | 203,474 |
| | $ | 4,150 |
| | $ | — |
| | $ | 207,624 |
|
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 revisitreview the Special Note Regarding Forward-Looking Statements.
EXECUTIVE SUMMARY
Financial Overview
Production volumes increased substantially to 6.0 MMboe and 15.86.6 MMboe for the three and nine months ended September 30, 2016, respectively,March 31, 2017, representing increasesan increase of 39% and 49%, respectively,46 percent as compared to the three and nine months ended September 30, 2015.March 31, 2016. The increase in production volumes was primarily attributable to the continued success of our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field. Field and our first full quarter of production from the newly-acquired Delaware Basin properties.Crude oil production increased 17% and 27%32 percent for the three and nine months ended September 30, 2016, respectively,March 31, 2017 compared to the same prior year periods.three months ended March 31, 2016. Crude oil production comprised approximately 39% and 40%38 percent of total production in the three and nine months ended September 30, 2016. Our ratio of crude oil production to total production decreased as compared to 2015 as expected as we shifted our focus to the higher gas to oil ratio inner core area of the Wattenberg Field during the first half of 2016. We expect our ratio of crude oil to total production to increase by the end of 2016 as we move drilling operations back toward the middle core area of the Wattenberg Field.March 31, 2017. Natural gas production increased 47% and 60%46 percent in the three and nine months ended September 30, 2016, respectively,March 31, 2017 compared to the three and nine months ended September 30, 2015. March 31, 2016.NGL production increased 80% and 83%75 percent for the three and nine months ended September 30, 2016, respectively,March 31, 2017 compared to the same prior year periods. Our innerthree months ended March 31, 2016. While our oil production has increased at a meaningful level, our middle core wells in the Wattenberg Field have shown strongerperformed even better, with wet gas production than anticipated, whichthat has outpaced oil and contributed to the growth of gas and NGL production. OurNGLs production at a relatively higher rate. On a combined basis, total liquids production comprised 61 percent of total production during each of the three months ended March 31, 2017 and March 31, 2016. For the month ended March 31, 2017, we maintained an average quarterly production rate of approximately 73,900 Boe per day, up from approximately 50,200 Boe per day for the three months ended September 30, 2016 increased approximately 0.8 MMboe, or 16%,March 31, 2016.
On a sequential quarterly basis, production volumes for the three months ended March 31, 2017, as compared to the three months ended June 30, 2016. We expect aDecember 31, 2016, increased by four percent. The modest increase in production was primarily related to the scheduled 46 wells turned-in-line for the fourththree months ended March 31, 2017 occurring in the later portion of the quarter as well completion activity resumed in January 2017 following a period in November and December 2016 in which no wells were completed. The decision to delay well completions created a two to three month delay in wells being turned-in-line, which resulted in the relatively flat production on a sequential basis. We expect the timing of 2016wells to be turned-in-line to sales during the remainder of 2017 to be relatively steady. When this trend is combined with our increased level of capital investment, we expect to have more substantial increases in sequential quarterly production volumes throughout the remainder of 2017 as compared to the third quarter, as we have approximately 20 fewer wells scheduled to be turned-in-line during the fourth quarter, and we expect all remaining 2016 well completions to be concluded by the middlethat of the fourth quarter ofthree months ended March 31, 2017, versus the three months ended December 31, 2016. For the month ended September 30, 2016, our average production rate was 63 MBoe per day, up from 47 MBoe per day for the month ended September 30, 2015.
Crude oil, natural gas, and NGLs sales coupled with the impact of settled derivatives, increased during the three and nine months ended September 30, 2016 relative to the same prior year periods. Crude oil, natural gas and NGLs sales increased to $141.8 million and $328 million during the three and nine months ended September 30, 2016 compared to $104.5 million and $275.5$189.7 million in the same prior year periods duethree months ended March 31, 2017, compared to 39% and 49% increases in production, respectively, offset in part by 2% and 20% decreases, respectively,$75.4 million in the realized price per barrel of crude oil equivalent ("Boe"). The realized prices per Boe were $23.62 and $20.80 for the three and nine months ended September 30, 2016, respectively, compared to $24.15March 31, 2016. This 152 percent increase in sales revenues was driven by the 73 percent increase in realized commodity prices and $26.02, respectively, for the same prior year periods. Positivea 46 percent increase in production. We had net commodity price risk management gains of $80.7 million and $11.1 million, of which $0.5 million and $66.8 million were positive net settlements, on derivatives decreased to $47.7 million for the three months ended September 30,March 31, 2017 and March 31, 2016, and increased to $167.9 million during the nine months ended September 30, 2016 compared to positive net settlements on derivatives of $68 million and $162.5 million in the same prior year periods. As a result of these aggregate changes,respectively. The combined revenue from crude oil, natural gas, and NGLs sales and the impact of net settled derivatives totaled $189.5settlements received on our commodity derivative instruments increased 34 percent to $190.2 million and $495.9 million duringin the three and nine months ended September 30, 2016, respectively, compared to $172.5March 31, 2017, from $142.2 million and $438 million duringin the three and nine months ended September 30, 2015, respectively. This represents increasesMarch 31, 2016.
Net settlements of 10% and 13% duringderivatives decreased significantly for the three and nine months ended September 30, 2016, respectively,March 31, 2017, as compared to the samethree months ended March 31, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior year periods. The realizedto commodity prices per Boe, includingbecoming depressed in late 2014. Substantially all of these high-value derivatives settled by the impactend of net2016. Net settlements on derivatives, were $31.56 and $31.44 for the three and nine months ended September 30, 2016, respectively,March 31, 2017, reflect derivative instruments entered into since mid-2014 which approximate recent realized prices. Based upon the forward strip pricing at March 31, 2017, we expect that settlements will be substantially lower on a relative basis as compared to $39.88 and $41.37 for the same prior year periods respectively.in 2016.
AdditionalIn the three months ended March 31, 2017, we generated net income of $46.1 million, or $0.70 per diluted share. During this same period, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $130.2 million, and we invested $199.4 million in the development and exploration of our oil and natural gas properties, exclusive of the change in accounts payable related to capital expenditures. Beginning in 2017, we have included non-cash stock-based compensation and exploration, geologic and geophysical expense to our adjusted EBITDAX calculation. In prior periods, we included adjusted EBITDA, a non-U.S. GAAP financial measure, that did not include these adjustments. All prior periods have been conformed for comparability of this updated presentation. In the same period of 2016, our net loss per diluted share was $1.72 and our adjusted EBITDAX, a non-GAAP financial measure, was $57.8 million. Our cash flow from operations was $139.5 million and our adjusted cash flow from operations, a non-U.S. GAAP financial measure, was $113.7 million in the three months ended March 31, 2017. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.
Other significant changes impacting our results of operations for the three months ended September 30, 2016March 31, 2017, include the following:
Negative net change in the fair value of unsettled derivative positions during the three months ended September 30, 2016 was $28.3 million compared to a positive net change in the fair value of unsettled derivative positions of $55.5 million during the same prior year period. The decrease in fair value of unsettled derivative positions was primarily attributable to a less significant upward shift in the crude oil and natural gas forward curves, offset by the impact of the beginning of period fair value of derivative instruments settled in the respective periods, during the current quarter as compared to the three months ended September 30, 2015;
Impairment of properties and equipment decreased to $0.9 million for the three months ended September 30, 2016 compared to $154 million in the same prior year period, primarily related to the $150.3 million write-down of our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value in the three months ended September 30, 2015;24
General and administrative expense increased to $32.5 million for the three months ended September 30, 2016 compared to $20.3 million in the same prior year period, primarily due to $11.3 million of fees and expenses related to the pending Delaware Basin Acquisition;
Depreciation, depletion and amortization expense increased to $112.9 million during the three months ended September 30, 2016 compared to $80.9 million in the same prior year period, primarily due to increased production; and
Interest expense increased to $20.2 million for the three months ended September 30, 2016 compared to $12.1 million in the same prior year period, primarily attributable to a $9 million charge for the bridge loan commitment related to the Delaware Basin Acquisition.
Additional significant changes impacting our results of operations for the nine months ended September 30, 2016 include the following:
NegativePositive net change in the fair value of unsettled derivative positions duringderivatives for the ninethree months ended September 30, 2016March 31, 2017 was $230.2$80.2 million, compared to a negative net change in the fair value of unsettled derivative positionsderivatives for the three months ended March 31, 2016 of $21.3 million during$55.7 million. The increase in the same prior year period. The decrease in fair value of unsettled derivative positions was primarily attributablederivatives is largely driven by a downward shift in the crude oil forward curve during the three months ended March 31, 2017, as compared to an upward shift in the crude oil and natural gas forward curves that occurredcurve during 2016;
Impairment of properties and equipment decreased to $6.1 million for the nine months ended September 30, 2016 compared to $161.2 million in the same prior year period, primarily related to the $150.3 million write-down of our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value in the three months ended September 30, 2015;
General and administrative expense increased to $78.9 million for the nine months ended September 30, 2016 compared to $62.1 million in the same prior year period, primarily due to $11.3 million of fees and expenses related to the Delaware Basin Acquisition;March 31, 2016.
Depreciation, depletion, and amortization expense increased to $317.3$109.3 million during the ninethree months ended September 30, 2016March 31, 2017, as compared to $206.9$97.4 million in the same prior year period,three months ended March 31, 2016. The increase was primarily due to increasedthe increase in production and an increase in the property balance during the three months ended March 31, 2017 as compared to a lesser extent, a higher weighted-averagethe three months ended March 31, 2016. The increase in the property balance is due to our Delaware Basin acquisitions. Our depreciation, depletion, and amortization rate;
During the first quarter of 2016, we determined that collection of a third-party note receivable arising from the sale of our interest in properties in the Marcellus Shale was not reasonably assured based then current market conditions and new information made availableexpense decreased to us. As a result, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44 million outstanding balance as of March 31, 2016. As of September 30, 2016, there has been no change to our assessment of the collectibility of the note. See Note 3, Fair Value of Financial Instruments - Notes Receivable, to our condensed consolidated financial statements included elsewhere in this report for additional information; and
Interest expense increased to $42.8 million for the nine months ended September 30, 2016 compared to $35.4 million in the same prior year period, primarily attributable to a $9 million charge for the bridge loan commitment related to the Delaware Basin Acquisition.
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$16.44 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 the principal amount owed upon the maturity of the Convertible Notes in May 2016 and retained the remainder for general corporate purposes.
The 2016 Convertible Notes matured in May 2016. We settled the 2016 Convertible Notes with a combination of cash and stock, paying the aggregate principal amount, plus cash for fractional shares, totaling approximately $115 million, utilizing proceeds from the offering. Additionally, we issued 792,406 shares of common stock for the excess conversion value.
In June 2016, we entered into definitive agreements with Noble to consolidate certain acreage positions in the core Wattenberg Field.
In September 2016, we closed the acreage exchange transaction. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties. The difference in net acres is primarily due to variances in leasehold net revenue interests and third-party mid-stream contracts. This acreage trade is expected to increase opportunities for longer horizontal laterals with significantly increased working interests, while minimizing potential surface impact.
Pending Delaware Basin Acquisition
We seek acquisition opportunities as part of our overall growth strategy, and in particular have recently engaged in the process of searching for, and evaluating, a large-scale acquisition in a new U.S. onshore basin capable of creating material long-term value-added growth, focusing on four key criteria: top-tier acreage in core geologic positions, significant drilling inventory with additional expansion through downspacing, portfolio optionality for capital allocation and diversification and the ability to deliver long-term corporate accretion. In August 2016, we identified a potential acquisition, which we refer to as the Delaware Basin Acquisition, that we believe met our four key criteria.
We entered into definitive agreements relating to the Delaware Basin Acquisition in August 2016. The agreements contemplate that we will acquire an aggregate of approximately 57,000 net acres, approximately 30 wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $915 million in cash and approximately 9.4 million shares of our common stock (valued at approximately $590 million at the time the acquisition agreements were executed), subject to certain adjustments and ongoing due diligence. The acquisition agreements allow the sellers to include a specified amount of additional leases in the transaction, which would increase the purchase price. Upon executing the acquisition agreements, we paid a $100 million deposit toward the cash portion of the purchase price into an escrow account. In some circumstances set forth in the acquisition agreements, we could be required to forfeit the $100 million deposit. The Delaware Basin Acquisition is expected to initially increase our daily production by approximately 7,000 Boe per day. The acquisition is expected to close in December 2016; however, there can be no assurance conditions to closing will be satisfied. Upon closing, we currently expect to initially run a two rig drilling program in the Delaware Basin. We are currently completing our budgeting process for 2017, but anticipate running two to three rigs in the Delaware Basin during 2017. Taking into account the anticipated plans for the Delaware Basin Acquisition properties, we expect that pursuit of our development program will require capital in excess of our projected cash flows from operations for some period of time beginning in 2017.
In order to fund the cash portion of the Delaware Basin Acquisition, we completed a public offering of 9,085,000 shares of our common stock, a public offering of the 2021 Convertible Notes and a private offering of the 2024 Senior Notes in September 2016 (collectively, the "Securities Issuances"). The common stock was issued at a price to us of $61.51 per share for net proceeds of approximately $558.5 million, after deducting offering expenses and underwriting discounts. Net proceeds of the issuances of the 2021 Convertible Notes and 2024 Senior Notes were approximately $194 million and $392.3 million, respectively, after deducting offering expenses and underwriting discounts. If the Delaware Basin Acquisition is not completed on or prior to December 31, 2016 (or in some circumstances by or on January 15, 2017), the 2024 Senior Notes will be redeemed in whole at a special mandatory redemption price equal to 100% of the aggregate principal amount of the 2024 Senior Notes, plus accrued and unpaid interest.
Prior to the Securities Issuances, we entered into a commitment letter with JPMorgan regarding certain aspects of the temporary financing of the Delaware Basin Acquisition. The commitment letter contemplated, among other things, (i) a senior unsecured bridge loan to us in an aggregate principal amount not to exceed $600 million, to be drawn, if at all, at the closing of the Delaware Basin Acquisition, (ii) a $250 million increase in the commitments under our existing revolving credit facility and (iii) certain related proposed amendments and waivers to our existing credit facility agreement. We expect to fund the cash consideration payable in the Delaware Basin Acquisition with proceeds from the Securities Issuances. Following the completion of the Securities Issuances, the bridge loan commitment was terminated. Upon closing of the Delaware Basin Acquisition, we will be required to pay approximately $9 million in fees related to the bridge loan commitment, approximately $6 million in fees related to the increase in commitments under the revolving credit facility and approximately $10 million in other direct acquisition-related costs. During the three months ended September 30,March 31, 2017 from $21.31 per Boe during the three months ended March 31, 2016 we recorded charges for the bridge loan commitment fees and the other direct acquisition-related costs. The $9 million charge for fees related to the bridge loan commitment is included in interest expense and the $10 million charge for other direct acquisition-related costs is included in general and administrative expenses. The liabilities associated with both amounts are included in other accrued expenses onbecause of our condensed consolidated balance sheet as of September 30, 2016.
Liquidityincreased proved reserve profile;
Available liquidity as of September 30, 2016March 31, 2017, was $1,636$945.8 million compared to $402.2$932.4 million as of December 31, 2015.2016. Available liquidity as of September 30, 2016March 31, 2017 is comprised of $1,197.7$207.6 million of cash and cash equivalents, $49.9 million of short-term investments, and $438.3$688.3 million available for borrowing under our revolving credit facility. These amounts excludeOur liquidity will be impacted by our planned 2017 capital investment activities. We expect decreases in our cash balances over the course of 2017 as we continue development in the core Wattenberg Field and the expected capital investment in our Delaware Basin assets.
We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flow from our operations, investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an additional $250 million availableactive commodity derivative hedging program, utilization of our borrowing capacity under our revolving credit facility, that will be available followingand when warranted, the closingutilization of the Delaware Basin Acquisition and may be available in other circumstances subjectcapital markets transactions from time to certain terms and conditions of the agreement. In October 2016, we completed the semi-annual redetermination of our revolving credit facility by the lenders, which resulted in the reaffirmation of the borrowing base at $700 million. We have elected to maintain the aggregate commitment level at $450 million until the closing of the Delaware Basin Acquisition. Cash and cash equivalents as of September 30, 2016 included approximately $392.3 million of proceeds from the issuance of the 2024 Senior Notes. If, however, the Delaware Basin Acquisition is not completed prior to or on December 31, 2016 (or in some circumstances by or on January 15, 2017), the $400 million principal amount of the 2024 Senior Notes is required to be redeemed with interest. If required, we will redeem the 2024 Senior Notes with available cash. 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 the cash portion of the purchase price for the Delaware Basin Acquisition and execute our expected 2016 development program.
The following table presents our liquidity as of September 30, 2016 pro forma for the closing of the Delaware Basin Acquisition, reflecting cash to be paid and the increase in the aggregate commitments under our revolving credit facility:
|
| | | | |
As of September 30, 2016 | | Amount |
| | (in millions) |
Cash and cash equivalents | | $ | 1,197.7 |
|
Available for borrowing under our credit facility | | 438.3 |
|
Available liquidity | | 1,636.0 |
|
Increase in aggregate commitments under our revolving credit facility | | 250.0 |
|
Cash due upon closing of the Delaware Basin Acquisition (1) | | (840.0 | ) |
Adjusted liquidity | | $ | 1,046.0 |
|
__________
(1)Amount includes total cash portion of purchase price due to sellers, less $100 million deposit in escrow and estimated acquisition-related costs. Amount does not reflect potential purchase price adjustments to be determined upon and post closing.
Operational Overview
During the ninethree months ended September 30, 2016,March 31, 2017, we continued to execute our strategic plan to grow production while preserving our financial strength and liquidity. Through July 2016,During the three months end March 31 2017, we ran four automatedoperated three drilling rigs in the Wattenberg Field. In August 2016, we decreased the number of automated drillingField and two increasing to three rigs running in the Wattenberg Field to three in anticipation of higher working interests in wells drilled resulting from the aforementioned acreage exchange with Noble. During the nine months ended September 30, 2016, we spud 107 horizontal wells and turned-in-line 121 horizontal wells in the Wattenberg Field.Delaware Basin. We also participated in 11 gross, 2.8 net, horizontal non-operated wells that were spud and 24 gross, 5.0 net, horizontal non-operated wells which were turned-in-line. During the nine months ended September 30, 2016, we drilled and completed five wellsdid not have a drilling rig operating in the Utica Shale three of which were turned-in-line during the period. Of
The following table summarizes our drilling and completion activity for the three months ended March 31, 2017:
|
| | | | | | | | | | | | | | | | | | |
| | Wattenberg Field | | Delaware Basin | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
In-process as of December 31, 2016 | | 76 |
| | 55.5 |
| | 5 |
| | 4.8 |
| | 81 |
| | 60.3 |
|
Wells spud during the period | | 42 |
| | 26.2 |
| | 7 |
| | 6.7 |
| | 49 |
| | 32.9 |
|
Wells turned-in-line to sales | | (43 | ) | | (32.7 | ) | | (3 | ) | | (3.0 | ) | | (46 | ) | | (35.7 | ) |
In-process as of March 31, 2017 | | 75 |
| | 49.0 |
| | 9 |
| | 8.5 |
| | 84 |
| | 57.5 |
|
Our in-process wells represent wells that are in the process of being drilled and/or have been drilled and are waiting to be fractured and/or for gas pipeline connection. We do not have a practice of inventorying our drilled but uncompleted wells. The majority of these threein-process wells oneat each period end are drilled but not completed as we do not begin the completion process until the entire well pad is an approximately 10,000 foot lateral well locateddrilled. All appropriate costs incurred through the end of the period have been capitalized, while the capital investment to complete the wells will be incurred in Guernsey County and twothe period in which the wells are approximately 6,000 foot lateral wells located in Washington County. We plan to turn-in-line the two remaining wells over the next several months.completed.
20162017 Operational Outlook
We previously announced that we expect our production for 2016the full year 2017 to be at the high end or slightly exceed the 21.0range between 30.0 MMBoe to 22.0 MMBoe range disclosed earlier33.0 MMBoe. Based on the timing and estimated productivity of wells associated with our capital investment program, we currently believe that our production will come in at levels in the yeartop third of the range. We expect that approximately 41 percent of our 2017 production will be crude oil and approximately 22 percent will be NGLs, for total liquids of approximately 63 percent of our production rate for December 2016 to exceed 71,000 Boe per day, including the impact of expected production from the Delaware Basin Acquisition, assuming the acquisition closes in December 2016.2017 production. Our revised 2016 capital forecast of $400between $725 million to $420and $775 million is focused on continuing to provide value-driven production growth by exploiting our substantial inventory of projectscontinued development in the core Wattenberg Field. Currently, excluding acquisition costs that we expect to incurField and the continued integration and development of the core Delaware Basin assets. We added the third rig in 2016 related to the Delaware Basin Acquisition, we expect to be near or slightly belowsooner than originally anticipated and have adjusted the low end of the expected range of our capital expenditures.costs per
25
well in the Delaware Basin up from our initial estimates to reflect higher service costs during the first quarter of 2017. Our total capital investment program will vary based on the number of wells ultimately drilled and completed. Based on the current operating plan and current cost estimates, we expect that our 2017 capital investment program will be in the upper half of the range.
Colorado Ballot Initiative UpdateWattenberg Field. The 2017 investment forecast of approximately $470 million in the Wattenberg Field anticipates a three to four-rig drilling program based on our current commodity price outlook. Approximately $460 million of our 2017 capital investment program is expected to be allocated to development activities, comprised of approximately $440 million for our operated drilling program and approximately $20 million for wells drilled and operated by others. The remainder of the Wattenberg Field capital investment program is expected to be used for miscellaneous well equipment and capital projects. Wells in the Wattenberg Field typically have productive horizons at a depth of approximately 6,500 to 7,500 feet below the surface. In 2017, we anticipate spudding approximately 139 and turning-in-line approximately 139 horizontal operated wells with lateral lengths of 4,000 to 10,000 feet.
During 2016, certain interest groups in Colorado opposedDelaware Basin. Our 2017 investment forecast contemplates the operation of a two-rig to oil and natural gas development generally, or hydraulic fracturing in particular, advanced various options for ballot initiatives aimed at significantly limiting or effectively preventing oil and natural gas developmentfour-rig program in the stateDelaware Basin from time to time during the year. Total capital investment in the Delaware Basin is estimated to be $290 million, of Colorado. Proponentswhich approximately $225 million is allocated to spud 32 and turn-in-line an estimated 23 wells. Of the 23 planned turn-in-lines, 11 are expected to have laterals of two such initiatives attemptedapproximately 10,000 horizontal feet with an estimated 70 to qualify75 completion stages per well. Similarly spaced completion stages are anticipated for the initiativesremaining 12 turn-in-lines. Wells in the Delaware Basin typically have productive horizons at a depth of approximately 9,000 to appear11,000 feet below the surface. Based on the ballot fortiming of our operations and the November 2016 election. On August 29, 2016, the Colorado Secretary of State issued a press release and statements of insufficiency of signatures, stating that the proponentsrequirements to hold acreage, we may adapt our capital investment program to drill wells in addition to those currently anticipated, as we are continuing to analyze terms of the proposals had failedleaseholds related to collect enough valid signaturesour recent acquisitions of properties in the basin. We plan to haveinvest approximately $30 million for leasing, seismic, and technical studies with an additional $35 million for midstream-related projects including gas connections, salt water disposal wells, and surface location infrastructure.
We will incur costs associated with the proposals included onpurchase of seismic data and pilot hole exploratory work in the ballot.Delaware Basin, which will be accounted for as exploration, geologic, and geophysical expense. We anticipate that this will result in approximately $5 million to $10 million of exploration expense in 2017.
One of the initiatives, which we refer to as the “local control” initiative, would have amended the state constitution to give city, town and county governments the right to regulate, or to ban, oil and gas development and production within their boundaries, notwithstanding rules and approvals to the contrary at the state level. This proposal was motivated in part byUtica Shale. As a decision of the Colorado Supreme Court earlier this year holding that local government restrictions on oil and gas activities are subject to preemption by state rules.
A second initiative, which we refer to as the “setback” initiative, would have amended the state constitution to require all new oil and gas development facilities to be located at least 2,500 feet away from any occupied structure or broadly defined “area of special concern,” including public and community drinking water sources, lakes, rivers, perennial or intermittent streams, creeks, irrigation canals, riparian areas, playgrounds, permanent sports fields, amphitheaters, public parks and public open space.
If implemented, the setback initiative would have effectively prohibited the vast majorityresult of our planned future drilling activities in Colorado and would therefore have made it impossible to pursue our current development plans. The local control proposal would potentially have had a similar effect, depending on the nature and extent of regulations implemented by relevant local governmental authorities. Pursuant to the determination of the Colorado Secretary of State, these proposals will not appear on the November 2016 ballot. However, future proposals of this nature are possible.
Because substantially allevaluation of our current operations and reserves are located in Colorado, the risks we facestrategic alternatives with respect to suchour Utica Shale position, we expect to divest these properties during 2017. As of March 31, 2017, these assets did not meet the accounting criteria to be classified as held for sale; therefore, they continue to be included in properties and equipment on our condensed consolidated balance sheets. We will continue to evaluate the classification of these assets in future proposals are greater than those ofquarters. Minimal capital is expected to be committed to our competitors with more geographically diverse operations. Although we cannot predict the outcome of future ballot initiatives, statutes or regulatory developments, such developments could materially impact our results of operations, production and reserves.Utica Shale assets in 2017.
Results of Operations
Summary Operating Results
The following table presents selected information regarding our operating results:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| 2016 | | 2015 | | Percentage Change | | 2016 | | 2015 | | Percentage Change | 2017 | | 2016 | | Percentage Change |
| (dollars in millions, except per unit data) | (dollars in millions, except per unit data) |
Production (1) | | | | | | | | | | | | | | | | |
Crude oil (MBbls) | 2,339.8 |
| | 2,007.8 |
| | 16.5 | % | | 6,240.2 |
| | 4,895.9 |
| | 27.5 | % | 2,508 |
| | 1,908 |
| | 31.5 | % |
Natural gas (MMcf) | 13,417.4 |
| | 9,148.9 |
| | 46.7 | % | | 36,768.2 |
| | 22,997.0 |
| | 59.9 | % | 15,584 |
| | 10,678 |
| | 45.9 | % |
NGLs (MBbls) | 1,428.1 |
| | 793.0 |
| | 80.1 | % | | 3,402.8 |
| | 1,858.5 |
| | 83.1 | % | 1,543 |
| | 882 |
| | 74.8 | % |
Crude oil equivalent (MBoe) (2) | 6,004.2 |
| | 4,325.6 |
| | 38.8 | % | | 15,771.0 |
| | 10,587.3 |
| | 49.0 | % | 6,648 |
| | 4,570 |
| | 45.5 | % |
Average MBoe per day | 65.3 |
| | 47.0 |
| | 38.8 | % | | 57.6 |
| | 38.8 |
| | 49.0 | % | |
Average Boe per day | | 73,866 |
| | 50,216 |
| | 47.1 | % |
Crude Oil, Natural Gas and NGLs Sales | | | | | | | | | | | | | | | | |
Crude oil | $ | 98.5 |
| | $ | 78.3 |
| | 25.8 | % | | $ | 233.0 |
| | $ | 206.7 |
| | 12.7 | % | $ | 123.0 |
| | $ | 54.0 |
| | 127.8 | % |
Natural gas | 27.4 |
| | 18.8 |
| | 45.7 | % | | 59.6 |
| | 49.4 |
| | 20.6 | % | 36.9 |
| | 14.9 |
| | 147.7 | % |
NGLs | 15.9 |
| | 7.4 |
| | 114.9 | % | | 35.4 |
| | 19.4 |
| | 82.5 | % | 29.8 |
| | 6.5 |
| | 358.5 | % |
Total crude oil, natural gas and NGLs sales | $ | 141.8 |
| | $ | 104.5 |
| | 35.7 | % | | $ | 328.0 |
| | $ | 275.5 |
| | 19.1 | % | |
Total crude oil, natural gas, and NGLs sales | | $ | 189.7 |
| | $ | 75.4 |
| | 151.6 | % |
| | | | | | | | | | | | | | | | |
Net Settlements on Derivatives (3) | | | | | | | | | | | | |
Net Settlements on Commodity Derivatives (1) | | | | | | |
Crude oil | $ | 39.5 |
| | $ | 60.7 |
| | (34.9 | )% | | $ | 131.6 |
| | $ | 142.4 |
| | (7.6 | )% | $ | (3.2 | ) | | $ | 53.3 |
| | * |
|
Natural gas | 8.2 |
| | 7.3 |
| | 12.3 | % | | 36.3 |
| | 20.1 |
| | 80.6 | % | 3.7 |
| | 13.5 |
| | (72.6 | )% |
Total net settlements on derivatives | $ | 47.7 |
| | $ | 68.0 |
| | (29.9 | )% | | $ | 167.9 |
| | $ | 162.5 |
| | 3.3 | % | $ | 0.5 |
| | $ | 66.8 |
| | (99.3 | )% |
| | | | | | | | | | | | | | | | |
Average Sales Price (excluding net settlements on derivatives) | | | | | | | | | | | | | | | | |
Crude oil (per Bbl) | $ | 42.11 |
| | $ | 38.98 |
| | 8.0 | % | | $ | 37.33 |
| | $ | 42.22 |
| | (11.6 | )% | $ | 49.04 |
| | $ | 28.29 |
| | 73.3 | % |
Natural gas (per Mcf) | 2.04 |
| | 2.05 |
| | (0.5 | )% | | 1.62 |
| | 2.15 |
| | (24.7 | )% | 2.37 |
| | 1.39 |
| | 70.5 | % |
NGLs (per Bbl) | 11.12 |
| | 9.40 |
| | 18.3 | % | | 10.41 |
| | 10.45 |
| | (0.4 | )% | 19.29 |
| | 7.37 |
| | 161.7 | % |
Crude oil equivalent (per Boe) | 23.62 |
| | 24.15 |
| | (2.2 | )% | | 20.80 |
| | 26.02 |
| | (20.1 | )% | 28.53 |
| | 16.49 |
| | 73.0 | % |
| | | | | | | | | | | | | | | | |
Average Lease Operating Expenses (per Boe) (4) | | | | | | | | | | | | |
Wattenberg Field | $ | 2.39 |
| | $ | 3.31 |
| | (27.8 | )% | | $ | 2.77 |
| | $ | 4.24 |
| | (34.7 | )% | |
Utica Shale | 1.27 |
| | 1.74 |
| | (27.0 | )% | | 1.87 |
| | 1.77 |
| | 5.6 | % | |
Weighted-average | 2.33 |
| | 3.20 |
| | (27.2 | )% | | 2.73 |
| | 4.04 |
| | (32.4 | )% | |
| | | | | | | | | | | | |
Natural Gas Marketing Contribution Margin (5) | $ | (0.4 | ) | | $ | (0.2 | ) | | 100.0 | % | | $ | (1.1 | ) | | $ | (0.6 | ) | | (83.3 | )% | |
| | | | | | | | | | | | |
Other Costs and Expenses | | | | | | | | | | | | |
Average Costs and Expenses (per Boe) | | | | | | |
Lease operating expenses | | $ | 2.98 |
| | $ | 3.35 |
| | (11.0 | )% |
Production taxes | $ | 9.6 |
| | $ | 5.5 |
| | 74.7 | % | | $ | 19.7 |
| | $ | 13.2 |
| | 49.0 | % | 1.87 |
| | 0.89 |
| | 110.1 | % |
Transportation, gathering and processing expenses | 5.0 |
| | 3.9 |
| | 28.2 | % | | 13.6 |
| | 6.6 |
| | 105.9 | % | 0.89 |
| | 0.88 |
| | 1.1 | % |
Impairment of properties and equipment | 0.9 |
| | 154.0 |
| | (99.4 | )% | | 6.1 |
| | 161.2 |
| | (96.2 | )% | |
General and administrative expense | 32.5 |
| | 20.3 |
| | 60.3 | % | | 78.9 |
| | 62.1 |
| | 27.1 | % | 3.96 |
| | 4.98 |
| | (20.5 | )% |
Depreciation, depletion and amortization | 112.9 |
| | 80.9 |
| | 39.5 | % | | 317.3 |
| | 206.9 |
| | 53.4 | % | 16.44 |
| | 21.31 |
| | (22.9 | )% |
Provision for uncollectible notes receivable | (0.7 | ) | | — |
| | * |
| | 44.0 |
| | — |
| | * |
| |
| | | | | | | | | | | | | | | | |
Interest expense | $ | 20.2 |
| | $ | 12.1 |
| | 67.0 | % | | $ | 42.8 |
| | $ | 35.4 |
| | 20.8 | % | |
Lease Operating Expenses by Operating Region (per Boe) | | | | | | |
Wattenberg Field | | $ | 2.66 |
| | $ | 3.40 |
| | (21.8 | )% |
Delaware Basin | | 6.48 |
| | — |
| | * |
|
Utica Shale | | 1.60 |
| | 2.50 |
| | (36.0 | )% |
| |
* | Percentage change is not meaningful or equal to or greater than 300%.meaningful. |
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, natural gas 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. |
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 September 30, | | Nine Months Ended September 30, |
Production by Operating Region | | 2016 | | 2015 | | Percentage Change | | 2016 | | 2015 | | Percentage Change |
Crude oil (MBbls) | | | | | | | | | | | | |
Wattenberg Field | | 2,216.3 |
| | 1,868.6 |
| | 18.6 | % | | 5,928.5 |
| | 4,509.5 |
| | 31.5 | % |
Utica Shale | | 123.5 |
| | 139.2 |
| | (11.3 | )% | | 311.7 |
| | 386.4 |
| | (19.3 | )% |
Total | | 2,339.8 |
| | 2,007.8 |
| | 16.5 | % | | 6,240.2 |
| | 4,895.9 |
| | 27.5 | % |
Natural gas (MMcf) | | | | | | | | | | | | |
Wattenberg Field | | 12,700.0 |
| | 8,478.3 |
| | 49.8 | % | | 34,968.2 |
| | 21,040.7 |
| | 66.2 | % |
Utica Shale | | 717.4 |
| | 670.6 |
| | 7.0 | ��% | | 1,800.0 |
| | 1,956.3 |
| | (8.0 | )% |
Total | | 13,417.4 |
| | 9,148.9 |
| | 46.7 | % | | 36,768.2 |
| | 22,997.0 |
| | 59.9 | % |
NGLs (MBbls) | | | | | | | | | | | | |
Wattenberg Field | | 1,353.0 |
| | 730.6 |
| | 85.2 | % | | 3,240.4 |
| | 1,692.5 |
| | 91.5 | % |
Utica Shale | | 75.1 |
| | 62.4 |
| | 20.4 | % | | 162.4 |
| | 166.0 |
| | (2.2 | )% |
Total | | 1,428.1 |
| | 793.0 |
| | 80.1 | % | | 3,402.8 |
| | 1,858.5 |
| | 83.1 | % |
Crude oil equivalent (MBoe) | | | | | | | | | | | | |
Wattenberg Field | | 5,686.0 |
| | 4,012.3 |
| | 41.7 | % | | 14,996.9 |
| | 9,708.8 |
| | 54.5 | % |
Utica Shale | | 318.2 |
| | 313.3 |
| | 1.6 | % | | 774.1 |
| | 878.5 |
| | (11.9 | )% |
Total | | 6,004.2 |
| | 4,325.6 |
| | 38.8 | % | | 15,771.0 |
| | 10,587.3 |
| | 49.0 | % |
Amounts may not recalculate due to rounding.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Average Sales Price by Operating Region | | | | | | Percentage Change | | | | | | Percentage Change |
(excluding net settlements on derivatives) | | 2016 | | 2015 | | | 2016 | | 2015 | |
Crude oil (per Bbl) | | | | | | | | | | | | |
Wattenberg Field | | $ | 42.29 |
| | $ | 38.90 |
| | 8.7 | % | | $ | 37.42 |
| | $ | 42.13 |
| | (11.2 | )% |
Utica Shale | | 38.93 |
| | 40.02 |
| | (2.7 | )% | | 35.61 |
| | 43.28 |
| | (17.7 | )% |
Weighted-average price | | 42.11 |
| | 38.98 |
| | 8.0 | % | | 37.33 |
| | 42.22 |
| | (11.6 | )% |
Natural gas (per Mcf) | | | | | | | | | | | | |
Wattenberg Field | | $ | 2.08 |
| | $ | 2.11 |
| | (1.4 | )% | | $ | 1.63 |
| | $ | 2.17 |
| | (24.9 | )% |
Utica Shale | | 1.33 |
| | 1.36 |
| | (2.2 | )% | | 1.44 |
| | 1.92 |
| | (25.0 | )% |
Weighted-average price | | 2.04 |
| | 2.05 |
| | (0.5 | )% | | 1.62 |
| | 2.15 |
| | (24.7 | )% |
NGLs (per Bbl) | | | | | | | | | | | | |
Wattenberg Field | | $ | 11.07 |
| | $ | 9.62 |
| | 15.1 | % | | $ | 10.32 |
| | $ | 10.36 |
| | (0.4 | )% |
Utica Shale | | 12.14 |
| | 6.80 |
| | 78.5 | % | | 12.22 |
| | 11.40 |
| | 7.2 | % |
Weighted-average price | | 11.12 |
| | 9.40 |
| | 18.3 | % | | 10.41 |
| | 10.45 |
| | (0.4 | )% |
Crude oil equivalent (per Boe) | | | | | | | | | | | | |
Wattenberg Field | | $ | 23.77 |
| | $ | 24.32 |
| | (2.3 | )% | | $ | 20.83 |
| | $ | 26.07 |
| | (20.1 | )% |
Utica Shale | | 20.98 |
| | 22.04 |
| | (4.8 | )% | | 20.26 |
| | 25.47 |
| | (20.5 | )% |
Weighted-average price | | 23.62 |
| | 24.15 |
| | (2.2 | )% | | 20.80 |
| | 26.02 |
| | (20.1 | )% |
Amounts may not recalculate due to rounding.
For the three and nine months ended September 30, 2016,March 31, 2017, crude oil, natural gas, and NGLs sales revenue increased compared to the three and nine months ended September 30, 2015March 31, 2016 due to the following:following (in millions):
|
| | | | | | | |
| September 30, 2016 |
| Three Months Ended | | Nine Months Ended |
| (in millions) |
Increase in production | $ | 27.7 |
| | $ | 102.5 |
|
Increase (decrease) in average crude oil price | 7.3 |
| | (30.5 | ) |
Decrease in average natural gas price | (0.1 | ) | | (19.4 | ) |
Increase (decrease) in average NGLs price | 2.4 |
| | (0.1 | ) |
Total increase in crude oil, natural gas and NGLs sales revenue | $ | 37.3 |
| | $ | 52.5 |
|
|
| | | |
Increase in production | $ | 28.7 |
|
Increase in average crude oil price | 52.0 |
|
Increase in average natural gas price | 15.2 |
|
Increase in average NGLs price | 18.4 |
|
Total increase in crude oil, natural gas and NGLs sales revenue | $ | 114.3 |
|
Crude Oil, Natural Gas, and NGLs Production
The following tables present crude oil, natural gas, and NGLs production. Our acquisitions of assets in the Delaware Basin closed in December 2016; therefore, there is no comparative data for the third quarter of 2016 was 6.0 million Boe, up from 4.3 million Boe in the third quarter of 2015. Year-to-date, production was 15.8 million Boe, up from 10.6 million Boe in the first nine months of 2015. Production increased as a result of continued drilling and completion activities as discussed in Operational Overview.ended March 31, 2016:
|
| | | | | | | | | |
| | Three Months Ended March 31, |
Production by Operating Region | | 2017 | | 2016 | | Percentage Change |
Crude oil (MBbls) | | | | | | |
Wattenberg Field | | 2,142 |
| | 1,818 |
| | 17.8 | % |
Delaware Basin | | 275 |
| | — |
| | * |
|
Utica Shale | | 91 |
| | 90 |
| | 2.3 | % |
Total | | 2,508 |
| | 1,908 |
| | 31.5 | % |
Natural gas (MMcf) | | | | | | |
Wattenberg Field | | 13,714 |
| | 10,170 |
| | 34.8 | % |
Delaware Basin | | 1,246 |
| | — |
| | * |
|
Utica Shale | | 624 |
| | 508 |
| | 23.0 | % |
Total | | 15,584 |
| | 10,678 |
| | 45.9 | % |
NGLs (MBbls) | | | | | | |
Wattenberg Field | | 1,358 |
| | 840 |
| | 61.7 | % |
Delaware Basin | | 131 |
| | — |
| | * |
|
Utica Shale | | 54 |
| | 42 |
| | 27.3 | % |
Total | | 1,543 |
| | 882 |
| | 74.8 | % |
Crude oil equivalent (MBoe) | | | | | | |
Wattenberg Field | | 5,786 |
| | 4,354 |
| | 32.9 | % |
Delaware Basin | | 613 |
| | — |
| | * |
|
Utica Shale | | 249 |
| | 216 |
| | 15.3 | % |
Total | | 6,648 |
| | 4,570 |
| | 45.5 | % |
* Percentage change is not meaningful.
Amounts may not recalculate due to rounding.
From time to time, our production has beenwas adversely affected by high line pressures in the natural gas gathering facilities in the Wattenberg Field. SuchThis situation improved significantly in 2015 as a result of the investment in additional field processing by the primary midstream service provider in the basin. Line pressures did not materially affect our production forduring the threemonths endedMarch 31, 2017 or nine 2016 due to the aforementioned investment by our midstream providers and a decrease in development activity by certain producers in the Wattenberg Field. During the threemonths ended September 30, 2016. March 31, 2017 and 2016, approximately 91 percent and 88 percent, respectively, of our production in the Wattenberg Field was delivered from horizontal wells, with the remaining production coming from vertical wells. Horizontal wells typically have greater producing capacity and higher well pressures, and therefore tend to be more resilient to the negative impacts of high line pressures as compared to vertical wells.
We rely on our third-party midstream service providers to construct compression, gathering, and processing facilities to keep pace with our and the overall field's production growth. We anticipate gathering system pressures to vary throughout the year, with increases coinciding with the warmer summer months and expected field-wide production increases. We also expect that with our increased production and the development activities of other producers in the region,
pressures will increase somewhat during 2017. Accordingly, we have reflected estimates of this impact in our forecast range for production. In order to manage this situation, we, along with other operators in the Wattenberg Field, continue to work closely with our third-party midstream providers in an effort to ensure adequate system capacity going forward.forward as evidenced by a recent commitment of DCP Midstream, LP ("DCP") to build additional gathering and processing in the field. This expansion of gathering and processing facilities is expected to improve natural gas gathering pipelines and processing facilities and assist in the control of line pressures in the Wattenberg Field. In December 2016, in anticipation of our future drilling activities in the Wattenberg Field, we entered into a facilities expansion agreement with DCP to expand and improve its natural gas gathering pipelines and processing facilities. We will be bound to the incremental volume requirements in this agreement on the first day of the calendar month after the actual in-service date of the plant, which is estimated to be currently September 30, 2018. The agreement requires a baseline volume commitment. We are also required for the first three years of the contract to guarantee a certain target profit margin to the midstream provider on these volumes sold. Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments. Using the NYMEX forward pricing strip at March 31, 2017, the target profit margin would be achieved without an additional payment from us. See footnote titled Commitments and Contingencies for additional details regarding the agreement. The ultimate timing and availability of adequate infrastructure including potential line pressure impacts in 2017, is not within our control and if our midstream provider's construction projects are delayed, we could experience higher line pressures that may negatively impact our ability to fulfill our growth plans. Total system infrastructure needs may also be affected by a number of factors, including potential increases in production from the Wattenberg Field and warmer than expected weather.
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 NGL prices are among the most volatilehave a high degree of all commodity prices. While the price ofvolatility and our realizations can change substantially. Our realized prices for crude oil, decreasednatural gas, and NGLs increased significantly during the first nine monthsquarter of 20162017 compared to the first nine monthsquarter of 2015,2016. NYMEX crude oil and natural gas prices increased during the third quarter of 201655 percent and 59 percent, respectively, as compared to the first half of 2016 as the number of U.S. crude oil rigs and inventories declined. Natural gas prices decreased during the first nine months of 2016 when compared to the same prior year period. Although we did experience improved pricing by the end of the third quarter of 2016, due to an oversupply of nearly all domestic NGLs products, our average realized sales price for NGLs during the first nine months of 2016 reflected the same low levels seen during 2015. With the initiation of ethane exports and increased demand for NGLs, we are starting to see NGL prices trend upward.2016.
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 six months to deliver crude oil to competitive markets and these agreements have resulted in significantly improved deductions compared to the comparable period in 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 use29
The following tables present weighted-average sales price of crude oil, atnatural gas, and NGLs for the wellhead by pipeline from severalperiods presented. Our acquisitions of our padsassets in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability and reducingDelaware Basin closed in December 2016; therefore, there is no comparative data for 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 2016. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual pad 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.ended March 31, 2016:
Natural gas prices vary by region and locality, depending upon the distance |
| | | | | | | | | | | |
| | Three Months Ended March 31, |
Weighted-Average Realized Sales Price by Operating Region | | | | | | Percentage Change |
(excluding net settlements on derivatives) | | 2017 | | 2016 | |
Crude oil (per Bbl) | | | | | | |
Wattenberg Field | | $ | 49.12 |
| | $ | 28.37 |
| | 73.1 | % |
Delaware Basin | | 49.28 |
| | — |
| | * |
|
Utica Shale | | 46.55 |
| | 26.69 |
| | 74.4 | % |
Weighted-average price | | 49.04 |
| | 28.29 |
| | 73.3 | % |
Natural gas (per Mcf) | | | | | | |
Wattenberg Field | | $ | 2.38 |
| | $ | 1.39 |
| | 71.2 | % |
Delaware Basin | | 1.98 |
| | — |
| | * |
|
Utica Shale | | 2.98 |
| | 1.43 |
| | 108.4 | % |
Weighted-average price | | 2.37 |
| | 1.39 |
| | 70.5 | % |
NGLs (per Bbl) | | | | | | |
Wattenberg Field | | $ | 18.64 |
| | $ | 7.18 |
| | 159.6 | % |
Delaware Basin | | 22.58 |
| | — |
| | * |
|
Utica Shale | | 27.75 |
| | 11.24 |
| | 146.9 | % |
Weighted-average price | | 19.29 |
| | 7.37 |
| | 161.7 | % |
Crude oil equivalent (per Boe) | | | | | | |
Wattenberg Field | | $ | 28.19 |
| | $ | 16.49 |
| | 71.0 | % |
Delaware Basin | | 30.93 |
| | — |
| | * |
|
Utica Shale | | 30.55 |
| | 16.60 |
| | 84.0 | % |
Weighted-average price | | 28.53 |
| | 16.49 |
| | 73.0 | % |
* Percentage change is not meaningful.
Amounts may not recalculate due 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 the remainder of 2016 and into 2017.
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. While NGL prices had been declining, we have seen a stabilization of prices in 2016.rounding.
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"net-back method of accounting for natural gas and NGLs, as well as the majority of our crude oil production from the Wattenberg Field, for all commodities in the Delaware Basin, and for crude oil from the Utica Shale, as the majority of the purchasers of these commodities also provide transportation, gathering, and processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds, or have fixed our sales price at index less a specified deduction. We sell our commodities at the wellhead, or what is equivalent to the wellhead in situations where we gather multiple wells into larger pads, 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 reflectedtherefore embedded in the
wellhead price. The net-back method results in the recognition of a net sales price that is belowlower than the indices for which the production is based.based because the operating costs and profit of the midstream facilities are embedded in the net price we earn. We use the "gross"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.services as a function of the price we earn. Rather, we contract separately with the midstream provider for the applicable transport and processing based on a per unit basis. 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 nine months ended September 30, 2016, our Wattenberg Field crude oil average sales price increased approximately $1.24 per barrel relative to the benchmark price because we recognized the costs for transportation on the White Cliffs and Saddle Butte pipelines as an increase in transportation expense, rather than as a deduction from revenues.
Lease Operating Expenses
Lease operating expenses duringAs discussed above, we enter into agreements for the three months ended September 30, 2016 increased $0.2 million as compared tosale and transportation, gathering and processing of our production, the three months ended September 30, 2015, primarily due to increasesterms of $0.8 millionwhich can result in variances in the per unit realized prices that we receive for payroll and employee benefits and $0.8 million for leased compressors to address increases in line pressure. These increases were partially offset by decreases of $1 million related to mechanical integrity testing of wells and $0.2 million in environmental project costs. Lease operating expenses during the nine months ended September 30, 2016 increased $0.3 million as compared to the nine months ended September 30, 2015, primarily due to increases of $1.6 million for payroll and employee benefits, $1.1 million for leased compressors to address line pressure issues and $1 million for various other lease operating expenses. These increases were partially offset by decreases of $2.6 million for environmental project costs and $0.7 million for plugging and abandonment costs. Lease operating expenses per Boe decreased 27% and 32% to $2.33 and $2.73 during the three and nine months ended September 30, 2016, respectively, compared to $3.20 and $4.04 during the three and nine months ended September 30, 2015, respectively. The significant decreases in lease operating expense per Boe were the result of production growth of 39% and 49%, respectively.
Production Taxes
Production taxes are directly related toour crude oil, natural gas and NGLs sales. The $4.1 million increase in production taxes during the three months ended September 30, 2016 compared to the three months ended September 30, 2015 was primarilyNGLs. Information related to the 36% increasecomponents and classifications in the condensed consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based upon average daily prices throughout each month and our natural gas and NGLs sales, as well as higher severance tax ratesaverage NYMEX pricing is based upon projectedfirst-of-the-month index prices as this is how the majority of each of these commodities are sold pursuant to terms of the respective sales revenue. The $6.5 million increase in production taxes duringagreements. For NGLs, we use the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015 was primarily related to the 19% increase inNYMEX crude oil natural gas and NGLs sales,price as well as higher severance tax rates due to higher projected sales revenue coupled with a decrease in ad valorem tax credits available from 2015 production due to depressed commodity pricing in 2015.
Transportation, Gathering and Processing Expenses
reference for presentation purposes. The $1.1 million increase inaverage realized price before transportation, gathering, and processing expenses duringshown in the three months ended September 30, 2016 compared to the three months ended September 30, 2015 was mainly attributable to oil transportation costs on the Saddle Butte pipeline as we began delivering crude oil on this pipeline in December 2015. The $7 million increase in transportation, gathering and processing expenses during the nine months ended September 30, 2016, compared to the nine months ended September 30, 2015, was mainly attributable to oil transportation costs 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 totable below represents our long-term transportation agreements.approximate composite barrel price for NGLs.
|
| | | | | | | | | | | | | | | | | | | |
For the three months ended March 31, 2017 | | Average NYMEX Price | | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | | Average Realized Price Before Transportation, Gathering and Processing Expenses | | Average Transportation, Gathering and Processing Expenses | | Average Realized Price After Transportation, Gathering and Processing Expenses |
Crude oil (per Bbl) | | $ | 51.92 |
| | 94 | % | | $ | 49.04 |
| | $ | 1.58 |
| | $ | 47.46 |
|
Natural gas (per MMBtu) | | 3.32 |
| | 71 | % | | 2.37 |
| | 0.06 |
| | 2.31 |
|
NGLs (per Bbl) | | 51.92 |
| | 37 | % | | 19.29 |
| | 0.22 |
| | 19.07 |
|
Crude oil equivalent (per Boe) | | 39.42 |
| | 72 | % | | 28.53 |
| | 0.89 |
| | 27.64 |
|
| | | | | | | | | | |
For the three months ended March 31, 2016 | | Average NYMEX Price | | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | | Average Realized Price Before Transportation, Gathering and Processing Expenses | | Average Transportation, Gathering and Processing Expenses | | Average Realized Price After Transportation, Gathering and Processing Expenses |
Crude oil (per Bbl) | | $ | 33.45 |
| | 85 | % | | $ | 28.29 |
| | $ | 1.55 |
| | $ | 26.74 |
|
Natural gas (per MMBtu) | | 2.09 |
| | 67 | % | | 1.39 |
| | 0.07 |
| | 1.32 |
|
NGLs (per Bbl) | | 33.45 |
| | 22 | % | | 7.37 |
| | 0.31 |
| | 7.06 |
|
Crude oil equivalent (per Boe) | | 25.31 |
| | 65 | % | | 16.49 |
| | 0.88 |
| | 15.61 |
|
Commodity Price Risk Management, Net
We use variouscommodity derivative instruments to manage fluctuations in crude oil, natural gas, and crude oilNGLs prices. We have in place a variety of collars, fixed-price swaps, and basis swaps on a portion of our estimated crude oil, natural gas, and crude oilpropane production. Because we sell all of our crude oil, natural gas, and crude oilNGLs production at prices similarrelated to the indexes inherent in our underlying derivative instruments, adjusted for certain fees and surcharges stipulated in the applicable sales agreements, we ultimately realize a price, before contract fees,value 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 value related to our swaps, less deductions.the swaps. See Note 4,the footnote titled Commodity Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for a detailed presentation of our derivative positions as of September 30, 2016.March 31, 2017.
Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments and the change in fair value of unsettled commodity derivatives related to our crude oil, and natural gas, and propane production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales fromother income and costother expenses.
Net settlements of commodity derivative instruments are based on the difference between the crude oil, 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 gaspropane index prices at maturitythe settlement date of our commodity derivative instruments compared to the respective strike prices. Netprices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net assetvalue increase or decrease in the beginning-of- periodbeginning-of-period fair value of commodity derivative instruments that settled during the period, and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The corresponding impact of settlement of the commodity derivative instruments that settled during the period is included in net settlements for the period as discussed above. Netperiod. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil, and natural gas, and NGLs forward curves and changes in basis index pricing. See Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for a detailed description of net settlements on our various derivatives.certain differentials.
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 September 30, | | Nine Months Ended September 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in millions) |
Commodity price risk management gain (loss), net: | | | | | | | |
Net settlements: | | | | | | | |
Crude oil | $ | 39.5 |
| | $ | 60.7 |
| | $ | 131.6 |
| | $ | 142.4 |
|
Natural gas | 8.2 |
| | 7.3 |
| | 36.3 |
| | 20.1 |
|
Total net settlements | 47.7 |
| | 68.0 |
| | 167.9 |
| | 162.5 |
|
Change in fair value of unsettled derivatives: | | | | | | | |
Reclassification of settlements included in prior period changes in fair value of derivatives | (40.6 | ) | | (48.1 | ) | | (169.5 | ) | | (140.2 | ) |
Crude oil fixed price swaps | 3.3 |
| | 50.4 |
| | (33.8 | ) | | 51.4 |
|
Crude oil collars | 1.5 |
| | 28.5 |
| | (14.5 | ) | | 28.6 |
|
Natural gas fixed price swaps | 5.4 |
| | 19.5 |
| | (10.7 | ) | | 31.0 |
|
Natural gas basis swaps | 1.4 |
| | (1.0 | ) | | 0.7 |
| | (2.4 | ) |
Natural gas collars | 0.7 |
| | 6.2 |
| | (2.4 | ) | | 10.3 |
|
Net change in fair value of unsettled derivatives | (28.3 | ) | | 55.5 |
| | (230.2 | ) | | (21.3 | ) |
Total commodity price risk management gain (loss), net | $ | 19.4 |
| | $ | 123.5 |
| | $ | (62.3 | ) | | $ | 141.2 |
|
|
| | | | | | | |
| Three Months Ended March 31, |
| 2017 | | 2016 |
| (in millions) |
Commodity price risk management gain, net: | | | |
Net settlements of commodity derivative instruments: | | | |
Crude oil fixed price swaps and collars | $ | (3.2 | ) | | $ | 53.3 |
|
Natural gas fixed price swaps and collars | 3.6 |
| | 13.5 |
|
Natural gas basis protection swaps | 0.1 |
| | — |
|
Total net settlements of commodity derivative instruments | 0.5 |
| | 66.8 |
|
Change in fair value of unsettled commodity derivative instruments: | | | |
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments | 9.1 |
| | (58.9 | ) |
Crude oil fixed price swaps and collars | 56.2 |
| | (4.2 | ) |
Natural gas fixed price swaps and collars | 11.2 |
| | 7.8 |
|
Natural gas basis swaps | 3.3 |
| | (0.4 | ) |
Propane fixed price swaps | 0.4 |
| | — |
|
Net change in fair value of unsettled commodity derivative instruments | 80.2 |
| | (55.7 | ) |
Total commodity price risk management gain, net | $ | 80.7 |
| | $ | 11.1 |
|
Net settlements of commodity derivatives decreased significantly for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior to commodity prices becoming depressed in late 2014. Substantially all of these agreements had settled by the end of 2016. Net settlements for the three months ended March 31, 2017 reflect derivative instruments entered into since mid-2014 which approximate recent realized prices. Based upon the forward strip pricing at March 31, 2017, we expect that settlements will be substantially lower on a relative basis as compared to periods in 2016.
Lease Operating Expenses
Lease operating expenses decreased 11 percent to $2.98 per Boe during the three months ended March 31, 2017, compared to $3.35 per Boe during the three months ended March 31, 2016.The decrease in lease operating expense per Boe was predominately driven by the production growth of 46 percent, which was partially offset by a higher lease operating expense of $6.48 per Boe in the Delaware Basin. Aggregate lease operating expenses during the three months ended March 31, 2017 increased $4.5 million as compared to the three months ended March 31, 2016, primarily due to increases of $3.7 million related to operations in the Delaware Basin, $1.2 million for payroll and employee benefits due to a 13 percent average increase in headcount for the three months ended March 31, 2017, as compared to the three months ended March 31, 2016, and $0.7 million for workover projects. We expect continued increases in our headcount through the remainder of 2017 as we build out our Delaware Basin production team. We expect much of this increased cost of personnel will be offset by increases in our production. These increases were partially offset by a decrease of $1.2 million related to environmental project costs.
Production Taxes
Production taxes are directly related to crude oil, natural gas, and NGLs sales and are generally assessed as a percentage of net revenues. Production taxes are comprised mainly of severance tax and ad valorem tax. There are a number of adjustments to the statutory rates for these taxes based on certain credits that are determined based on activity levels and relative commodity prices from year-to-year. The $8.3 million increase in production taxes during the three months ended March 31, 2017, compared to the three months ended March 31, 2016 was primarily related to the 152 percent increase in crude oil, natural gas, and NGLs sales and an increase in our effective tax rate to approximately seven percent for the three months ended March 31, 2017 as compared to six percent for the three months ended March 31, 2016. These increases were partially offset by year-end return adjustments.Production taxes per Boe increased to $1.87 for the three months ended March 31, 2017 compared to $0.89 for the three months ended March 31, 2016.
Transportation, Gathering, and Processing Expenses
The $1.9 million increase in transportation, gathering, and processing expenses during the three months ended March 31, 2017, compared to the three months ended March 31, 2016, was mainly attributable to a $1.0 million increase in oil transportation costs due to increased volumes delivered through the Saddle Butte pipeline in the Wattenberg Field and a $0.7 million increase related to compressor rentals for our Delaware Basin properties. The use of pipelines allows us to deliver crude oil to the Cushing, Oklahoma market, where we benefit from the liquidity associated with the purchasers’ delivery point. Additional benefits of utilization of pipelines are decreased field truck traffic and decreased air emissions. Transportation, gathering, and processing expenses per Boe increased to $0.89 for the three months ended March 31, 2017 compared to $0.88 for the three months ended March 31, 2016.
Impairment of Properties and Equipment
Impairment of proved and unproved properties. Amounts represent the retirement of certain leases that were no longer part of our development plan or that we are not able to extend prior to termination of the lease. Deterioration of commodity prices or other operating circumstances could result in additional impairment charges.
The following table sets forth the major components of our impairment of properties and equipment expense:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in millions) |
| | | | | | | |
Impairment of proved and unproved properties | $ | 0.3 |
| | $ | 150.8 |
| | $ | 2.4 |
| | $ | 152.8 |
|
Amortization of individually insignificant unproved properties | 0.6 |
| | 3.2 |
| | 0.7 |
| | 8.4 |
|
Impairment of crude oil and natural gas properties
| 0.9 |
| | 154.0 |
| | 3.1 |
| | 161.2 |
|
Land and buildings | — |
| | — |
| | 3.0 |
| | — |
|
Impairment of properties and equipment | $ | 0.9 |
| | $ | 154.0 |
| | $ | 6.1 |
| | $ | 161.2 |
|
Impairment of proved and unproved properties. Due to a significant decline in commodity prices and a decrease in net-back realizations in the third quarter of 2015, we experienced a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded an impairment charge during the three months ended September 30, 2015 of $150.3 million to write-down our Utica Shale proved and unproved properties. Of this impairment charge, $24.7 million was recorded to write-down certain capitalized well costs on our Utica Shale proved producing properties. Additionally, as a result of the outlook for future commodity prices at that time, we recorded an impairment charge of $125.6 million to write-down all of our Utica Shale lease acquisition costs and pad development costs for pads not in production. Future 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. The decreases in amortization during the three and nine months ended September 30, 2016 compared to the three and nine months ended September 30, 2015 were due to an impairment in the third quarter of 2015 that significantly reduced the carrying value of our Utica Shale leases.
Land and buildings. The impairment charge for the nine months ended September 30, 2016 represents the excess of the carrying value over the estimated fair value, less the cost to sell, of a field operating facility in Greeley, Colorado, and 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters. The fair values of these assets were determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input.
PDC ENERGY, INC.
|
| | | | | | | |
| Three Months Ended March 31, |
| 2017 | | 2016 |
| (in millions) |
| | | |
Impairment of proved and unproved properties | $ | 2.1 |
| | $ | 0.9 |
|
Amortization of individually insignificant unproved properties | 0.1 |
| | 0.1 |
|
Total impairment of properties and equipment | $ | 2.2 |
| | $ | 1.0 |
|
General and Administrative Expense
General and administrative expense increased $12.2$3.5 million to $32.5$26.3 million for the three months ended September 30, 2016March 31, 2017 compared to $20.3$22.8 million for the three months ended September 30, 2015.March 31, 2016. The increase was primarily attributable to $11.3 million of fees and expenses related to the Delaware Basin Acquisition and a $1.2 million increase in payroll and employee benefits.
General and administrative expense increased $16.8 million to $78.9 million for the nine months ended September 30, 2016 compared to $62.1 million for the nine months ended September 30, 2015. The increase was primarily attributable to $11.3 million of fees and expenses related to the Delaware Basin Acquisition, a $4.5$2.3 million increase in payroll and employee benefits anddue to a $0.6 million13 percent average increase in costsheadcount for consultingthe three months ended March 31, 2017 as compared to the three months ended March 31, 2016, and other$0.5 million of professional services.services fees related to the Delaware Basin acquisitions. We expect continued increases in our headcount through the remainder of 2017 as we build out our Delaware Basin operations.
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 $112.1 million and $314.4$107.8 million for the three and nine months ended September 30, 2016March 31, 2017 compared to $79.8 million and $203.5$96.3 million for the three and nine months ended September 30, 2015.March 31, 2016. The period-over-period change in DD&A expense related to crude oil and natural gas properties was primarily due to the following:following (in millions):
| | | | September 30, 2016 | |
| | Three Months Ended | | Nine Months Ended | |
| | (in millions) | | | |
Increase in production | | $ | 32.0 |
| | $ | 104.1 |
| | $ | 38.4 |
|
Increase in weighted-average depreciation, depletion and amortization rates | | 0.3 |
| | 6.8 |
| |
Decrease in weighted-average depreciation, depletion and amortization rates | | | (26.9 | ) |
Total increase in DD&A expense related to crude oil and natural gas properties | | $ | 32.3 |
| | $ | 110.9 |
| �� | $ | 11.5 |
|
The following table presents our DD&A expense rates for crude oil and natural gas properties:
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Operating Region/Area | | 2016 | | 2015 | | 2016 | | 2015 |
| | (per Boe) |
Wattenberg Field | | $ | 19.17 |
| | $ | 19.10 |
| | $ | 20.42 |
| | $ | 19.92 |
|
Utica Shale | | 9.59 |
| | 10.08 |
| | 10.52 |
| | 11.49 |
|
Total weighted-average | | 18.66 |
| | 18.44 |
| | 19.94 |
| | 19.22 |
|
|
| | | | | | | | |
| | Three Months Ended March 31, |
Operating Region/Area | | 2017 | | 2016 |
| | (per Boe) |
Wattenberg Field | | $ | 16.94 |
| | $ | 21.72 |
|
Delaware Basin | | 11.46 |
| | — |
|
Utica Shale | | 11.24 |
| | 8.19 |
|
Total weighted-average | | 16.22 |
| | 21.08 |
|
Non-crude oil and natural gas properties.Depreciation expense for non-crude oil and natural gas properties was $0.9 million and $2.9$1.5 million for the three and nine months ended September 30, 2016, respectively,March 31, 2017 compared to $1.2 million and $3.4$1.1 million for the three and nine months ended September 30, 2015, respectively.March 31, 2016.
Provision for Uncollectible Notes Receivable
DuringIn the first quarter of 2016, we recorded a provision for uncollectible notes receivable of $44.7 million to impair two third-party notes receivable whose collection was not reasonably assured. DuringAs described in the three months ended September 30, 2016, we subsequently collected a $0.7 million promissory note and reversed the related provision and allowance for uncollectible notes receivable. See Note 3,footnote titled Fair Value of Financial Instruments - Notes Receivable, in April 2017, we signed a definitive agreement and simultaneously closed on the sale of one of the associated notes receivable to our condensed consolidated financial statements included elsewherean unrelated third party. Accordingly, we reversed $40.3 million of the provision for notes receivable in this report for additional information.
2017.
Interest Expense
Interest expense increased $8.1$7.6 million and $7.4to $19.5 million duringfor the three and nine months ended September 30, 2016March 31, 2017 compared to $11.9 million for the three and nine months ended September 30, 2015. March 31, 2016. The increases wereincrease is primarily attributable to a $9$6.3 million charge for the bridge loan commitment relatedincrease in interest relating to the Delaware Basin Acquisition, partially offset by decreasesissuance of our 2024 Senior Notes, a $2.6 million increase in interest expense onrelating to the issuance of our 2021 Convertible Notes, and a $0.7 million increase related to fees for the redetermination of the borrowing base under our revolving credit facility. The increases were offset by a $2.2 million decrease in interest expense from our 2016 Convertible Notes, as they maturedwhich were settled in May 2016.
Interest Income
Interest income decreased $1.2 million and $1.8 million during the three and nine months ended September 30, 2016 compared to the three and nine months ended September 30, 2015, as we ceased recognizing non-cash interest income on two third-party notes receivable.
Provision for Income Taxes
See Note 7, Income Taxes, to the accompanying condensed consolidated financial statements included elsewhere in this report for a discussion of the changes in ourThe effective tax rate for the three and nine months ended September 30, 2016March 31, 2017 was 36.3 percent expense on income compared to the three and nine months ended September 30, 2015. The effective tax rate of 34.0% and 37.1%36.9 percent benefit on loss for the three and nine months ended September 30, 2016, respectively,March 31, 2016. The effective tax rate for the three months ended March 31, 2017 is based onupon a full year forecasted pre-tax lossincome for the year adjusted for state tax, permanent differences and discrete items of tax.differences. The forecasted full year effective tax rate has been applied to the quarter-to-date pre-tax lossincome, resulting in a tax benefitexpense 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.
Our deferred income The additional tax liability at September 30, 2016 decreased $99.1 million comparedbenefit for stock-based compensation was the only discrete tax item reported for the three months ended March 31, 2017, and resulted in a 2.2 percent reduction to December 31, 2015. This decrease is primarily attributable to theour effective tax rate. There were no significant positive net settlements from derivativesdiscrete tax items recorded during the ninethree months ended September 30, 2016 and the significant reduction in fair value of unsettled derivatives held at September 30, 2016, partially offset by the $15 million deferred tax liability for the equity component of the 2021 Convertible Notes issued in SeptemberMarch 31, 2016.
Net Loss/Income (Loss)/Adjusted Net Income (Loss)
Net loss forThe factors resulting in changes in net income in the three and nine months ended September 30, 2016 was $23.3March 31, 2017 of $46.1 million, and $190.3 million compared toa net loss of $41.5 million and $71.3 million forin the three and nine months ended September 30, 2015. AdjustedMarch 31, 2016 of $71.5 million are discussed above. These same reasons similarly impacted adjusted net loss, a non-U.S. GAAP financial measure, was $5.8 million and $47.7 million for the three and nine months ended September 30, 2016 compared to adjusted net loss of $75.9 million and $58.1 million for the same prior year periods. The components of the quarter-over-quarter and year-over-year changes in net loss are discussed above. These changes similarly impacted adjusted net loss, with the exception of the tax affected net change in fair value of unsettled derivatives.derivatives, adjusted for taxes, of $50.2 million and $34.5 million for the three months ended March 31, 2017 and March 31, 2016, respectively. Adjusted net income (loss), a non-U.S. GAAP financial measure, was adjusted net loss of $4.1 million and $37.0 million for the three months ended March 31, 2017 and 2016, respectively. See Reconciliation of Non-U.S. GAAP Financial Measures, below for a more detailed discussion of this non-U.S. GAAP financial measure and reconciliation of this measure to the most comparable U.S. GAAP 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 capital market transactions, and asset sales. For the ninethree months ended September 30, 2016,March 31, 2017, our primary sources of liquidity were the net proceeds received from the March 2016 public offering of our common stock of $296.6 million, net proceeds from the Securities Issuances of approximately $1.1 billion, and net cash flows from operating activities of $360.8$139.5 million. We used a portion of the net proceeds of the March 2016 common stock offering to repay all amounts then outstanding on our revolving credit facility and the principal amount owed upon the maturity of the 2016 Convertible Notes in May 2016 and retained the remainder for general corporate purposes. The net proceeds from the Securities Issuances are expected to be used to fund a portion of the purchase price of the Delaware Basin Acquisition (see Note 6, Pending Acquisition), to pay related fees and expenses and for general corporate purposes.
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. The revolving credit agreement imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. 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 andBased upon our hedge position we expect that positive net settlements onand assuming forward strip pricing as of March 31, 2017, our derivative positions will continue toderivatives may not be a significant positive componentsource of our 2016cash flow in the near term, and may result in cash outflows in 2017 and 2018. During the three months ended March 31, 2017, we had $0.5 million of positive cash flows from operations.operations related to net settlements of commodity derivative instruments, compared to $66.8 million for the three months ended March 31, 2016. As of September 30, 2016,March 31, 2017, the fair value of our derivatives was a net asset of $33.5 million. Based on$10.1 million, of which $4.1 million will settle in the forward pricing strip at September 30, 2016, we would expect positive net settlements totaling approximately $39.3 million during the fourth quarterremaining nine months of 2016. However,2017 based upon our current hedge position and assuming currentforward strip pricing in 2017 and thereafter our derivatives may no longer be a significant sourceas of cash flow, and may result in cash outflows. Forthat date at the nine months ended September 30, 2016 and 2015, net settled derivatives comprised approximately 47% and 57%, respectively, of our cash flows from operating activities. See Part I, Item 3, Quantitative and Qualitative Disclosures about Market Risk, included elsewhere in this report for additional information regarding our derivatives positions by year of maturity.current price.
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 September 30, 2016,March 31, 2017, we had working capital of $1,148.8$93.8 million compared to $30.7$129.2 million at December 31, 2015.2016. The increasedecrease in working capital as of September 30, 2016March 31, 2017 is primarily the result of an increase in accounts payable of $78.1 million related to increased development and exploration activity, which was partially offset by an increase in the net fair value of our unsettled commodity derivative instruments of $45.4 million.
Our cash and cash equivalents related to the Securities Issuances and the repayment of the 2016 Convertible Notes in May 2016, offset in part by a decrease in the fair value of unsettled derivatives.
In recent periods, including the first nine months of 2016, we have been able to access borrowings underwere $207.6 million at March 31, 2017, our revolving credit facility and to obtain proceeds from the issuance of securities. We ended September 2016 with cash and cash equivalents of $1,197.7short-term investments were $49.9 million, and availability under our revolving credit facility of $438.3was $688.3 million, providing for a total liquidity position of $1,636$945.8 million as of March 31, 2017, compared to $402.2$932.4 million at December 31, 2015. These amounts exclude an additional $250 million available under our revolving credit facility that will be available following the closing of the Delaware Basin Acquisition and may be available in other circumstances subject to certain terms and conditions of the agreement.2016. The increase in liquidity of $1,233.8$13.4 million, or 306.8%, during the nine months ended September 30, 2016one percent, was primarily attributable to net cash flows from operating activities of $360.8$139.5 million, partially offset by capital investments associated with development and net cash flows from financing activitiesexploration activity of $1,284.8$129.8 million (including proceeds fromduring the Securities Issuances), offset in part by cash paid for capital expenditures of $353.7 million. Our liquidity position was reduced by the cash payment of approximately $115 million upon the maturity ofthree months ended March 31, 2017.
Based on our 2016 Convertible Notes in May 2016. With our current derivative position, liquidity position and expected cash flows from operations, our cash and cash equivalent and short-term investments balances and availability under our revolving credit facility, we believe that we have sufficient capital to fund the cash portion of the purchase price for the Delaware Basin Acquisition and our planned drilling operations foractivities during 2017. Our liquidity will be further augmented by the next 12 months. We cannot, however, assure sources$40.3 million of capital available to usproceeds received in the past will be available to us insecond quarter of 2017 from the future.sale of a third-party Note, as described previously.
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, 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 and, in September 2016, approximately nine million shares of our common stock in an underwritten public offering at a price to us of $61.51 per share and $200 million principal amount of convertible notes in an underwritten offering at par.
In September 2016, we entered into a Third Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, amends theOur revolving credit facility to permit the completion of the Delaware Basin Acquisitionis a borrowing base facility and effective upon closing of the acquisition, adjusts the interest rate payable on amounts borrowedavailability under the facility is subject to redetermination each May and increases the aggregate commitments under the facility from $450 million to $700 million (with the borrowing base remainingNovember, based upon a quantification of our proved reserves at $700 million).each June 30 and December 31, respectively. The maturity date of theour revolving credit facility is May 2020. As of March 31, 2017, the borrowing base is $700 million. Our ability to borrow under the revolving credit facility is limited under our 2022 Senior Notes to the greater of $700 million or the calculated value under an Adjusted Consolidated Tangible Net Asset test, as defined. The May 2017 redetermination of our borrowing base has not been finalized as of the date of this report.
Our borrowings bear interest at either an alternate base rate option or a LIBOR option as defined in the revolving credit facility plus an applicable margin, depending on the percentage of the commitment that has been utilized. As of March 31, 2017, the applicable margin is 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment fee is 0.50 percent.
We had no balance outstanding balance on our revolving credit facility as of September 30, 2016. WhileMarch 31, 2017. As of March 31, 2017, we have added and expecthad an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to continue to add producing reserves throughsecure a firm transportation obligation. As of March 31, 2017, the available funds under our drilling operations,revolving credit facility, including the effectreduction for the $11.7 million letter 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.credit, was $688.3 million.
In October 2016, we entered into the Fourth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, reaffirmed our borrowing base at $700 million and made certain other immaterial modifications to the existing agreement, including an increase in the amount we can hedge of our future production.
Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain:maintain (i) a leverage ratio defined as total debt of less than 4.254.0 times the trailing 12 months earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled commodity 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 1.0:1.0. 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 commodity 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. Effective upon closing of the Delaware Basin Acquisition, the maximum leverage ratio will be modified to a maximum of 4.00 to 1.00. At September 30, 2016,March 31, 2017, we were in compliance with all debt covenants with a 2.2 leverage ratio, as defined by the revolving credit agreement, of 2.0times debt to EBITDAX ratio and a 8.9 to 3.7:1.0current ratio. We expect to remain in compliance throughout the next year.12-month period.
The indentures governing our 20242022 Senior Notes and 20222024 Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt including under our revolving credit facility, (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 September 30, 2016,March 31, 2017, we were in compliance with all covenants and expect to remain in compliance throughout the next year.12-month period.
See Part I, Item 3, QuantitativeIn January 2017, pursuant to the filing of the supplemental indentures for the 2021 Convertible Senior Notes, the 2022 Senior Notes, and Qualitative Disclosures about Market Risk, forthe 2024 Senior Notes, our discussionsubsidiary PDC Permian, Inc. became a subsidiary guarantor of credit risk.the notes.
Cash Flows
Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs, and general and administrative expenses. Cash flows from operating activities increased by $77.8$38.4 million for the ninethree months ended September 30, 2016March 31, 2017 compared to the ninethree months ended September 30, 2015,March 31, 2016, primarily due to increases in crude oil, natural gas and NGLs sales of $52.5 million, net settlements from our derivative positions of $5.4$114.3 million and crude oil, and
thean increase in changes in assets and liabilities of $45.2$15.6 million related to the timing of cash payments and receipts. These increases were offset in part by a decrease in commodity derivative settlements of $66.3 million and increases in lease operating expenses of $4.5 million, production taxes of $8.3 million, general and administrative expenses of $16.8 million, transportation, gathering and processing expenses of $7$3.5 million, and production taxesinterest expense of $6.5$7.6 million. 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 $32.6$22.7 million during the ninethree months ended September 30, 2016,March 31, 2017 compared to the ninethree months ended September 30, 2015.March 31, 2016. 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,EBITDAX, a non-U.S. GAAP financial measure, decreasedincreased by $16.6$72.4 million during the ninethree months ended September 30, 2016March 31, 2017, compared to the ninethree months ended September 30, 2015.March 31, 2016. The decreaseincrease was primarily the result of recording a provision for uncollectible notes receivable of $44 million and the increases in transportation, gathering and processing expenses of $7 million, production taxes of $6.5 million and general and administrative expense of $16.8 million, offset in part by increases in crude oil, natural gas and NGLs sales of $52.5$114.3 million and netthe recording of a provision for uncollectible notes receivable of $44.7 million during the three months ended March 31, 2016. These increases were partially offset by a decrease in commodity derivative settlements from our derivative positions of $5.4$66.3 million and increases in lease operating expenses of $4.5 million, production taxes of $8.3 million, and general and administrative expenses of $3.5 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.investments.
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. Net cash used in investing activities of $448.8$173.6 million during the ninethree months ended September 30, 2016March 31, 2017, was primarily related to cash utilized for our drilling operations, including completion activities of $353.7$129.8 million and a $100purchases of short-term investments of $49.9 million. Partially offsetting these investments was the receipt of approximately $6.2 million deposit toward the cash portionrelated to post-closing settlements of the purchase price of the Delaware Basin Acquisition.properties acquired in 2016.
Financing Activities. Net cash from financing activities for the ninethree months ended September 30, 2016 increasedMarch 31, 2017 decreased by approximately $1,091.5$261.6 million compared to the ninethree months ended September 30, 2015. Net cash fromMarch 31, 2016. Certain capital markets and financing activities of $1,284.8 million foroccurred in 2016 including the nine months ended September 30, 2016 was primarily related to the $855.1$296.6 million received from the issuancesissuance of our common stock, $392.3 million of proceeds from issuance of the 2024 Senior Notes and $194 million of proceeds from issuance of the 2021 Convertible Notes,stock. These amounts were partially offset by the $115 million payment of principal amounts owed upon the maturity of the 2016 Convertible Notes and net payments of approximately $37$37.0 million to pay down amounts borrowed under our revolving credit facility.facility in the first quarter of 2016.
Drilling ActivityPDC ENERGY, INC.
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 September 30, | | Nine Months Ended September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
Operating Region/Area | | Productive | | In-Process | | Dry (1) | | Productive | | In-Process | | Dry (1) | | Productive | | In-Process | | Dry (1) | | Productive | | In-Process | | Dry (1) |
Development Wells | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field, operated wells | | 34.7 | | 40.1 | | — | | 26.5 | | 52.8 | | 1.1 | | 87.4 |
| | 40.1 |
| | 0.4 | | 75.0 |
| | 52.8 |
| | 2.1 |
|
Wattenberg Field, non-operated wells | | 1.8 | | 2.2 | | — | | 1.2 | | 4.9 | | — | | 5.0 |
| | 2.2 |
| | — | | 5.4 |
| | 4.9 |
| | — |
|
Utica Shale | | — | | 1.7 | | — | | — | | — | | — | | 2.8 |
| | 1.7 |
| | — | | 3.0 |
| | — |
| | — |
|
Total drilling activity | | 36.5 | | 44.0 | | — | | 27.7 | | 57.7 | | 1.1 | | 95.2 |
| | 44.0 |
| | 0.4 |
| | 83.4 |
| | 57.7 |
| | 2.1 |
|
______________(1) Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
Off-Balance Sheet Arrangements
At September 30, 2016,March 31, 2017, 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 expendituresinvestments, or capital resources.
Commitments and Contingencies
See Note 11,the footnote titled Commitments and Contingencies to the accompanying condensed consolidated financial statements included elsewhere in this report.
Recent Accounting Standards
See Note 2,the footnote titled 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 condensed consolidated financial statements and accompanying notes contained in our 20152016 Form 10-K filed with the SEC on February 22, 2016.28, 2017.
Reconciliation of Non-U.S. GAAP Financial Measures
We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDA,EBITDAX," 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. Beginning in 2017, we have included non-cash stock-based compensation and exploration, geologic and geophysical expense to our adjusted EBITDAX calculation. In prior periods, we included adjusted EBITDA, a non-U.S. GAAP financial measure, that did not include these adjustments. All prior periods have been
conformed for comparability of this information. 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 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 operationsoperations. . 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.EBITDAX. We define adjusted EBITDAEBITDAX as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of properties and equipment, exploration, geologic, and geophysical expense, depreciation, depletion and amortization expense, and accretion of asset retirement obligations, and non-cash stock-based compensation, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDAEBITDAX 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 EBITDAEBITDAX includes certain non-cash costs incurred by the Companyus and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDAEBITDAX differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDAEBITDAX 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.
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 September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| (in millions) | (in millions) |
Adjusted cash flows from operations: | | | | | | | | | | |
Net cash from operating activities | | $ | 139.5 |
| | $ | 101.2 |
|
Changes in assets and liabilities | | (25.8 | ) | | (10.2 | ) |
Adjusted cash flows from operations | $ | 122.6 |
| | $ | 122.7 |
| | $ | 326.2 |
| | $ | 293.6 |
| $ | 113.7 |
| | $ | 91.0 |
|
Changes in assets and liabilities | 40.4 |
| | 13.8 |
| | 34.6 |
| | (10.6 | ) | |
Net cash from operating activities | $ | 163.0 |
| | $ | 136.5 |
| | $ | 360.8 |
| | $ | 283.0 |
| |
| | | | | | | | | | |
Adjusted net loss: | | | | | | | | |
Adjusted net loss | $ | (5.8 | ) | | $ | (75.9 | ) | | $ | (47.7 | ) | | $ | (58.1 | ) | |
Gain (loss) on commodity derivative instruments | 19.4 |
| | 123.5 |
| | (62.3 | ) | | 141.2 |
| |
Adjusted net income (loss): | | | | |
Net income (loss) | | $ | 46.1 |
| | $ | (71.5 | ) |
Gain on commodity derivative instruments | | (80.7 | ) | | (11.1 | ) |
Net settlements on commodity derivative instruments | (47.7 | ) | | (68.0 | ) | | (167.9 | ) | | (162.5 | ) | 0.5 |
| | 66.8 |
|
Tax effect of above adjustments | 10.8 |
| | (21.1 | ) | | 87.6 |
| | 8.1 |
| 30.0 |
| | (21.2 | ) |
Net loss | $ | (23.3 | ) | | $ | (41.5 | ) | | $ | (190.3 | ) | | $ | (71.3 | ) | |
Adjusted net income (loss) | | $ | (4.1 | ) | | $ | (37.0 | ) |
| | | | | | | | | | |
Adjusted EBITDA to net loss: | | | | | | | | |
Adjusted EBITDA | $ | 128.7 |
| | $ | 129.1 |
| | $ | 297.4 |
| | $ | 314.0 |
| |
Gain (loss) on commodity derivative instruments | 19.4 |
| | 123.5 |
| | (62.3 | ) | | 141.2 |
| |
Net income (loss) to adjusted EBITDAX: | | | | |
Net income (loss) | | $ | 46.1 |
| | $ | (71.5 | ) |
Gain on commodity derivative instruments | | (80.7 | ) | | (11.1 | ) |
Net settlements on commodity derivative instruments | (47.7 | ) | | (68.0 | ) | | (167.9 | ) | | (162.5 | ) | 0.5 |
| | 66.8 |
|
Non-cash stock-based compensation | | 4.5 |
| | 4.7 |
|
Interest expense, net | (20.1 | ) | | (10.7 | ) | | (40.9 | ) | | (31.8 | ) | 19.2 |
| | 10.3 |
|
Income tax provision | 12.0 |
| | 21.2 |
| | 112.2 |
| | 40.6 |
| |
Income tax expense (benefit) | | 26.3 |
| | (41.8 | ) |
Impairment of properties and equipment | (0.9 | ) | | (154.0 | ) | | (6.1 | ) | | (161.2 | ) | 2.2 |
| | 1.0 |
|
Depreciation, depletion and amortization | (112.9 | ) | | (81.0 | ) | | (317.3 | ) | | (206.9 | ) | |
Exploration, geologic, and geophysical expense | | 1.0 |
| | 0.2 |
|
Depreciation, depletion, and amortization | | 109.3 |
| | 97.4 |
|
Accretion of asset retirement obligations | (1.8 | ) | | (1.6 | ) | | (5.4 | ) | | (4.7 | ) | 1.8 |
| | 1.8 |
|
Net loss | $ | (23.3 | ) | | $ | (41.5 | ) | | $ | (190.3 | ) | | $ | (71.3 | ) | |
Adjusted EBITDAX | | $ | 130.2 |
| | $ | 57.8 |
|
| | | | | | | | | | |
Adjusted EBITDA to net cash from operating activities: | | | | | | | | |
Adjusted EBITDA | $ | 128.7 |
| | $ | 129.1 |
| | $ | 297.4 |
| | $ | 314.0 |
| |
Cash from operating activities to adjusted EBITDAX: | | | | |
Net cash from operating activities | | $ | 139.5 |
| | $ | 101.2 |
|
Interest expense, net | (20.1 | ) | | (10.7 | ) | | (40.9 | ) | | (31.8 | ) | 19.2 |
| | 10.3 |
|
Stock-based compensation | 4.1 |
| | 4.8 |
| | 15.2 |
| | 14.3 |
| |
Amortization of debt discount and issuance costs | 9.9 |
| | 1.8 |
| | 12.9 |
| | 5.3 |
| (3.2 | ) | | (1.8 | ) |
Gain on sale of properties and equipment | (0.2 | ) | | (0.1 | ) | | — |
| | (0.3 | ) | 0.2 |
| | 0.1 |
|
Exploration, geologic, and geophysical expense | | 1.0 |
| | 0.2 |
|
Other | 0.2 |
| | (2.2 | ) | | 41.6 |
| | (7.9 | ) | (0.7 | ) | | (42.0 | ) |
Changes in assets and liabilities | 40.4 |
| | 13.8 |
| | 34.6 |
| | (10.6 | ) | (25.8 | ) | | (10.2 | ) |
Net cash from operating activities | $ | 163.0 |
| | $ | 136.5 |
| | $ | 360.8 |
| | $ | 283.0 |
| |
Adjusted EBITDAX | | $ | 130.2 |
| | $ | 57.8 |
|
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 2021 Convertible Notes, 2024 Senior Notes, and 2022 Senior Notes, and short-term investments 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 September 30, 2016,March 31, 2017, 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 September 30, 2016March 31, 2017 was $1,167$169.1 million with a weighted-average interest rate of 0.3%.0.5 percent. Based on a sensitivity analysis of our interest-bearing deposits as of September 30, 2016March 31, 2017 and assuming we had $1,167$169.1 million outstanding throughout the period, we estimate that a 1%1 percent increase in interest rates would have increased interest income for the ninethree months ended September 30, 2016March 31, 2017 by approximately $8.7$1.7 million.
As of September 30, 2016,March 31, 2017, 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, natural gas basis, and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil, and natural gas, natural gas basis, and propane prices we will receive for our hedged production. We believe that our commodity 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 September 30, 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 September 30, 2016 (2) (in millions) |
| | Floors | | Ceilings | | | | | |
Natural Gas | | | | | | | | | | | | | | | | |
NYMEX | | | | | | | | | | | | | | | | |
2016 | | 900.0 |
| | $ | 3.75 |
| | $ | 4.04 |
| | 7,805.0 |
| | $ | 3.67 |
| | 8,403.2 |
| | $ | (0.27 | ) | | $ | 5.3 |
|
2017 | | 7,920.0 |
| | 3.59 |
| | 4.13 |
| | 27,290.0 |
| | 3.55 |
| | 12,000.0 |
| | (0.28 | ) | | 17.0 |
|
2018 | | 1,230.0 |
| | 3.00 |
| | 3.67 |
| | 45,280.0 |
| | 2.94 |
| | 16,200.0 |
| | (0.28 | ) | | 2.4 |
|
| | | | | | | | | | | | | | | | |
Total Natural Gas | | 10,050.0 |
| | | | | | 80,375.0 |
| | | | 36,603.2 |
| | | | 24.7 |
|
| | | | | | | | | | | | | | | | |
Crude Oil | | | | | | | | | | | | | | | | |
NYMEX | | | | | | | | | | | | | | | | |
2016 | | 435.0 |
| | 77.59 |
| | 97.55 |
| | 930.0 |
| | 72.21 |
| | — |
| | — |
| | 34.0 |
|
2017 | | 1,464.0 |
| | 49.22 |
| | 65.95 |
| | 3,004.0 |
| | 44.92 |
| | — |
| | — |
| | (15.1 | ) |
2018 | | 1,512.0 |
| | 41.85 |
| | 54.31 |
| | 1,512.0 |
| | 51.06 |
| | — |
| | — |
| | (10.1 | ) |
| | | | | |
| | | | | | | | | | |
Total Crude Oil | | 3,411.0 |
| | | | | | 5,446.0 |
| | | | — |
| | | | 8.8 |
|
Total Natural Gas and Crude Oil | | | | | | | | | | | | | | | | $ | 33.5 |
|
| | | | | | | | | | | | | | | | |
____________
| |
(1) | A standard unit of measurement for natural gas (one BBtu equals one MMcf). |
| |
(2) | Approximately 33.1% of the fair value of our derivative assets and 19.2% 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. |
The following table presents our commodity and basis derivative positions related to crude oil, natural gas, and propane in effect as of March 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Collars | | Fixed-Price Swaps | | |
Commodity/ Index/ Maturity Period | | Quantity (Gas - BBtu Oil - MBbls) | | Weighted-Average Contract Price | | Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls) | | Weighted- Average Contract Price | | Fair Value March 31, 2017 (1) (in millions) |
| | Floors | | Ceilings | | | |
Crude Oil | | | | | | | | | | | | |
NYMEX | | | | | | | | | | | | |
2017 | | 1,848.0 |
| | $ | 49.54 |
| | $ | 62.32 |
| | 5,480.5 |
| | $ | 50.11 |
| | $ | (5.1 | ) |
2018 | | 1,512.0 |
| | 41.85 |
| | 54.31 |
| | 5,072.0 |
| | 53.85 |
| | 6.2 |
|
Total Crude Oil | | 3,360.0 |
| | | | | | 10,552.5 |
| | | | $ | 1.1 |
|
| | | | | | | | | | | | |
Natural Gas | | | | | | | | | | | | |
NYMEX | | | | | | | | | | | | |
2017 | | 8,550.3 |
| | $ | 3.40 |
| | $ | 4.05 |
| | 20,555.0 |
| | $ | 3.50 |
| | $ | 6.3 |
|
2018 | | 1,230.0 |
| | 3.00 |
| | 3.67 |
| | 45,280.0 |
| | 2.94 |
| | (3.0 | ) |
Total Natural Gas | | 9,780.3 |
| | | | | | 65,835.0 |
| | | | $ | 3.3 |
|
| | | | | | | | | | | | |
Basis Protection | | | | | | | | | | | | |
2017 | | — |
| | — |
| | — |
| | 21,104.0 |
| | $ | (0.29 | ) | | 2.5 |
|
2018 | | — |
| | — |
| | — |
| | 18,200.0 |
| | (0.29 | ) | | 2.8 |
|
Total Basis Protection | | — |
| | | | | | 39,304.0 |
| | | | $ | 5.3 |
|
| | | | | | | | | | | | |
Propane | | | | | | | | | | | | |
Mont Belvieu | | | | | | | | | | | | |
2017 | | — |
| | — |
| | — |
| | 535.7 |
| | $ | 26.78 |
| | $ | 0.4 |
|
Commodity Derivatives Fair Value | | | | | | | | $ | 10.1 |
|
| | | | | | | | | | | | |
____________
| |
(1) | Approximately 18.4 percent of the fair value of our commodity derivative assets and 16.9 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). |
In addition to our commodity derivative positions as of March 31, 2017, we entered into the following commodity derivative positions related to natural gas subsequent to March 31, 2017 that are effective as of April 18, 2017:
|
| | | | | | | | | | | | | | | | | | | |
| | Collars | | Fixed-Price Swaps |
Commodity/ Index/ Maturity Period | | Quantity (Gas - BBtu Oil - MBbls) | | Weighted-Average Contract Price | | Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls) | | Weighted- Average Contract Price |
| | Floors | | Ceilings | | |
Natural Gas | | | | | | | | | | |
NYMEX | | | | | | | | | | |
2017 | | — |
| | $ | — |
| | $ | — |
| | 7,000.0 |
| | $ | 3.42 |
|
2018 | | 4,000.0 |
| | 3.00 |
| | 3.50 |
| | — |
| — |
| — |
|
Total Natural Gas | | 4,000.0 |
| | | | | | 7,000.0 |
| | |
| | | | | | | | | | |
Basis Protection | | | | | | | | | | |
2017 | | — |
| | — |
| | — |
| | 14,000.0 |
| | $ | (0.39 | ) |
2018 | | — |
| | — |
| | — |
| | 6,000.0 |
| | (0.41 | ) |
Total Basis Protection |
| — |
| | | | | | 20,000.0 |
| | |
Our realized prices vary regionally based on local market differentials and our transportation agreements. The following table presents average NYMEX and CIG closingmarket index prices for crude oil and natural gas for the periods identified, as well as the average sales prices we realized for our crude oil, natural gas, and NGLs production:
|
| | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended | | Year Ended |
| September 30, 2016 | | September 30, 2016 | | December 31, 2015 |
Average Index Closing Price: | | | | | |
Crude oil (per Bbl) | | | | | |
NYMEX | $ | 44.94 |
| | $ | 41.33 |
| | $ | 48.80 |
|
Natural gas (per MMBtu) | | | | | |
NYMEX | $ | 2.81 |
| | $ | 2.29 |
| | $ | 2.66 |
|
CIG | 2.47 |
| | 1.98 |
| | 2.44 |
|
TETCO M-2 (1) | 1.47 |
| | 1.31 |
| | 1.49 |
|
| | | | | |
Average Sales Price Realized: | | | | | |
Excluding net settlements on derivatives | | | | | |
Crude oil (per Bbl) | $ | 42.11 |
| | $ | 37.33 |
| | $ | 40.14 |
|
Natural gas (per Mcf) | 2.04 |
| | 1.62 |
| | 2.04 |
|
NGLs (per Bbl) | 11.12 |
| | 10.41 |
| | 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. |
| | | | | | | |
| Three Months Ended | | Year Ended |
| March 31, 2017 | | December 31, 2016 |
Average NYMEX Index Price: | | | |
Crude oil (per Bbl) | $ | 51.92 |
| | $ | 43.32 |
|
Natural gas (per MMBtu) | 3.32 |
| | 2.46 |
|
| | | |
Average Sales Price Realized: | | | |
Excluding net settlements on commodity derivatives | | | |
Crude oil (per Bbl) | $ | 49.04 |
| | $ | 39.96 |
|
Natural gas (per Mcf) | 2.37 |
| | 1.77 |
|
NGLs (per Bbl) | 19.29 |
| | 11.80 |
|
Based on a sensitivity analysis as of September 30, 2016,March 31, 2017, we estimate that a 10%ten percent increase in natural gas, and crude oil, and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives in place, would have resulted in a decrease in the fair value of our derivative positions of $80.3$87.6 million, whereas a 10%10 percent decrease in prices would have resulted in an increase in fair value of $80.3$87.6 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 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 counterparty’s 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 Oiloil and Gas Explorationgas exploration and Production segment'sproduction business'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 segmentgas marketing business are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions, and end-users in various industries. The underlying operations of these entities are geographically concentrated in the same region, which increases the credit risk associated with this business. As natural gas prices continue to remain depressed, certain third-party producers underrelating to our Gas Marketing segment have begun andgas marketing business 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. 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 onetwo default judgment.judgments. We expect this trend to continue for this segment.business.
A group of 42 independent West Virginia natural gas producers has filed a lawsuit in Marshall County, West Virginia, naming Dominion, certain entities affiliated with Dominion, and RNG as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. RNG and Dominion have removed the case to the U.S. District Court for the Northern District of West Virginia and are preparing pre-trial pleadings, including an answer to the compliant and a motion to dismiss the case. At this time, RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defense.
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 commodity derivative financial instruments. See Note 4, the footnote titled Commodity Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial instruments.
Disclosure of Limitations
Because the information above included only those exposures that existed at September 30, 2016,March 31, 2017, 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.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of September 30, 2016,March 31, 2017, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Principal 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 Principal Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2016.March 31, 2017.
Changes in Internal Control over Financial Reporting
During the three months ended September 30, 2016,March 31, 2017, 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 ourFrom time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, 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 foundreasonably estimated. Except as discussed herein, we are not aware of any environmental claims existing as of March 31, 2017 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. Accrued environmental liabilities are recorded in Note 10, Commitments and Contingencies – Litigation, to ourother accrued expenses on the condensed consolidated financial statements included elsewherebalance sheets.
In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field 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. In December 2016, we received a draft consent decree from the EPA.
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 of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. This matter has been combined with the matter discussed above. We have ongoing discussions with the EPA, U.S. Department of Justice, and Colorado Department of Public Health and Environment regarding these matters. The ultimate outcome related to these combined actions has not been determined at this report.time.
Action Regarding Firm Transportation Contracts
In June 2016, a group of 42 independent West Virginia natural gas producers filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. ("Dominion"), certain entities affiliated with Dominion, and our subsidiary RNG as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. The case has been transferred to the Business Court Division of the Circuit Court of Marshall County, West Virginia, and the parties are awaiting that court's ruling on previously-filed pre-trial pleadings. RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses.
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 20152016 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.
There have been no material changes from the risk factors previously disclosed in our 20152016 Form 10-K, except for the following:
If completed, the Delaware Basin Acquisition may not achieve its intended results and may result in us assuming unanticipated liabilities. To date, we have conducted only limited diligence regarding the assets and liabilities we would assume in the transaction.
We entered into the Delaware Basin Acquisition agreements with the expectation that the acquisition would result in various benefits, growth opportunities and synergies. Achieving the anticipated benefits of the transaction is subject to a number of risks and uncertainties. For example, under the acquisition agreements, we have the opportunity to conduct customary environmental and title due diligence following the execution of the agreements, but our diligence efforts to date have been limited. As a result, we may discover title defects or adverse environmental or other conditions of which we are currently unaware. Environmental, title and other problems could reduce the value of the properties to us, and, depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We would assume substantially all of the liabilities associated with the acquired properties and would be entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure you that such potential remedies will be adequate for any liabilities we incur, and such liabilities could be significant. In addition, certain of the properties to be acquired are subject to consents to assign and preference rights. If all applicable waivers cannot be obtained, we may not be able to acquire certain properties as originally contemplated and our expected benefits of the acquisition may be adversely affected. Further, the acquisition agreements allow the sellers to include a specified amount of additional leases in the transaction, which would increase the purchase price. Also, it is uncertain whether our existing operations and the acquired properties and assets can be integrated in an efficient and effective manner.
As with other acquisitions, the success of the Delaware Basin Acquisition depends on, among other things, the accuracy of our assessment of the reserves and drilling locations associated with the acquired properties, future oil, NGL and natural gas prices and operating costs and various other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price for the acquisition from the sale of production from the property or recognize an acceptable return from such sales. See "-Risks Related to Our Business and the Industry-Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties" in our 2015 Form 10-K. Although the properties to be acquired are subject to many of the risks and uncertainties to which our business and operations are subject, risks associated with the Delaware Basin Acquisition in particular include those associated with our ability to operate efficiently in an area where we have no current operations, the significant size of the transaction relative to our existing operations, the fact that a substantial majority of the properties to be acquired are undeveloped and the additional indebtedness we have incurred in connection with the acquisition. We also expect that pursuing our future development plans for the properties to be acquired will require
capital in excess of our projected cash flows from operations for some period of time beginning in 2017, which may increase our need for external financing.
In addition, the integration of operations following the Delaware Basin Acquisition will require substantial attention from our management and other personnel, which may distract their attention from our day-to-day business and operations and prevent us from realizing benefits from other opportunities. Completing the integration process may be more expensive than anticipated, and we cannot assure you that we will be able to effect the integration of these operations smoothly or efficiently or that the anticipated benefits of the transaction will be achieved.
The reserves, production and drilling locations estimates with respect to the properties to be acquired in the Delaware Basin Acquisition may differ materially from the actual amounts.
The reserves, production and drilling locations estimates with respect to the properties to be acquired in the Delaware Basin Acquisition are based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines. Such analysis is based, in significant part, on data provided by the sellers. We cannot assure you that these estimates are accurate. After such data is further reviewed by us and our independent engineers, the actual reserves, production and number of viable drilling locations may differ materially from our expectations.
We have incurred significant transaction-related costs in connection with the Delaware Basin Acquisition and the related financing transactions.
We have incurred a number of significant transaction-related costs associated with the Delaware Basin Acquisition and the related financing transactions. We continue to assess the magnitude of these costs and additional unanticipated costs, including costs incurred in the integration of the properties to be acquired, which may be significant.
Failure to complete the Delaware Basin Acquisition could negatively affect our stock price as well as our business and financial results.
Closing of the Delaware Basin Acquisition is subject to a number of conditions. If the Delaware Basin Acquisition is not completed, we will be subject to a number of risks, including but not limited to the following:
We must pay costs related to the acquisition including, among others, legal, accounting and financial advisory fees, whether the acquisition is completed or not.
In some circumstances set forth in the acquisition agreements, we could be required to forfeit the $100 million aggregate deposit we made at the time the agreements were executed.
We may experience negative reactions from the financial markets.
We could be subject to litigation related to the failure to complete the acquisition.
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 |
| | | | |
July 1 - 31, 2016 | | 19,261 |
| | $ | 54.38 |
|
August 1 - 31, 2016 | | 440 |
| | 55.48 |
|
September 1 - 30, 2016 | | — |
| | — |
|
Total third quarter purchases | | 19,701 |
| | 54.40 |
|
| | | | |
|
| | | | | | | |
Period | | Total Number of Shares Purchased (1) | | Average Price Paid per Share |
| | | | |
January 1 - 31, 2017 | | 27,514 |
| | $ | 74.34 |
|
February 1 - 28, 2017 | | — |
| | — |
|
March 1 - 31, 2017 | | — |
| | — |
|
Total first quarter 2017 purchases | | 27,514 |
| | $ | 74.34 |
|
| | | | |
__________
| |
(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.
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 |
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31.2 | | Certification by PrincipalChief 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 |
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32.1** | | Certifications by Chief Executive Officer and PrincipalChief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. | | | | | | | | | | |
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99.1 | | Fourth Amendment to Third Amendment and Restated Credit Agreement | | | | | | | | | | X |
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101.INS | | XBRL Instance Document | | | | | | | | | | X |
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101.SCH | | XBRL Taxonomy Extension Schema Document | | | | | | | | | | X |
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101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document | | | | | | | | | | X |
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101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document | | | | | | | | | | X |
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101.LAB | | XBRL Taxonomy Extension Label Linkbase Document | | | | | | | | | | X |
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101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document | | | | | | | | | | X |
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*Management contract or compensatory arrangement. |
** Furnished herewith. |
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.
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| PDC Energy, Inc. |
| (Registrant) |
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Date: November 3, 2016May 5, 2017 | /s/ Barton R. Brookman |
| Barton R. Brookman |
| President and Chief Executive Officer |
| (principal executive officer) |
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| /s/ R. Scott MeyersDavid W. Honeyfield |
| R. Scott MeyersDavid W. Honeyfield |
| Senior Vice President and Chief AccountingFinancial Officer |
| (principal financial officer) |
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