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 SeptemberJune 30, 20152016
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)
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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 Tx 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 T xNo £o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
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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 |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ oNo Tx
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 40,107,52447,154,493 shares of the Company's Common Stock ($0.01 par value) were outstanding as of October 16, 2015.July 18, 2016.
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") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: the closing of pending transactions and the effects of such transactions, including the fact that the transactions contemplated by the Noble exchange agreements are subject to continuing diligence between the parties and accordingly, may not occur within the expected timeframe or at all; estimated future production (including the components of such production), sales, expenses, cash flows, liquidity and liquidity;balance sheet attributes; estimated crude oil, natural gas and natural gas liquids (“NGLs”) reserves, including 2015 year-end reserves; expected 2015 capital forecast allocations, including revised capital and production forecasts and that we expect to meet or exceed the high end of our range; anticipated increased 2015 capital projects and expenditures; expected year-end exit rates; the impact of prolonged depressed commodity prices; the Utica Shale impairmentprices, including potentially reduced production and other potential future impairments;associated cash flow; anticipated capital projects, expenditures and opportunities, including our expectation that 2016 cash flows from operations will approximate cash flows from investing activities; expected capital budget allocations; our operational flexibility and ability to revise our development plan, either upward or downward; availability of sufficient funding and liquidity for our 2015 capital program and sources of that funding; expected positive net settlements on derivatives in the second half of 2016; that we expect quarter-over-quarter production growth; future exploration, drilling and development activities, including ournon-operated activity, the number of drilling rigs we expect to run and lateral lengths of wells; expected rig count in both the Utica Shale2016 production and Wattenberg Field; expectationcash flow ranges and timing of cash flows in 2015 and 2016; potential additional revisions to our 2015 capital and production forecast; anticipated reductions in our 2015 cost structure; the expiration of certain leases and our current development plan in the Utica Shale;turn-in-lines; our evaluation method of our customers' and derivative counterparties' credit risk, including certain of our gas marketing customers; our expected positive net settlements on our derivative positions and effect on cash flow in 2015;risk; effectiveness of our derivative program in providing a degree of price stability; the impactpotential for future impairments; expected sustained relief of high line pressures and the timing, availability, cost and effect of additional midstream facilities and services going forward; expected differentials;gathering system pressure; compliance with debt covenants; expected funding sources for anticipated net settlement of our 3.25% convertibleand senior notes due 2016; thecovenants; impact of litigation on our results of operations and financial position; that we do not expect to pay dividends in the foreseeable future; our belief that certain proposed initiatives in Colorado may not qualify to be included on the ballot in 2016; and our future strategies, plans and objectives.
The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying quarterly materials, we may use the terms “outlook,” “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. In additionBecause such statements relate to beingevents or conditions further in the future, they are subject to additionalincreased levels of uncertainty generally, forward-looking statements regarding such prospective matters do not necessarily reflect the outcomes we view as the most likely to occur, but instead are shown to illustrate aspects of our business in the context of a variety of scenarios we believe to be plausible.uncertainty.
Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
changes in worldwide production volumes and demand, including economic conditions that might impact demand;
volatility of commodity prices for crude oil, natural gas and NGLs and the risk of an extended period of depressed prices;
reductions in the borrowing base under our revolving credit facility;
impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;
potential 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;
our ability to secure leases, drilling rigs, supplies and services at reasonable prices;
availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;
timing and receipt of necessary regulatory permits;
risks incidental to the drilling and operation of crude oil and natural gas wells;
future cash flows, liquidity and financial condition;
competition within the oil and gas industry;
availability and cost of capital;
reductions in the borrowing base under our revolving credit facility;
our success in marketing crude oil, natural gas and NGLs;
effect of crude oil and natural gas derivatives activities;
impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;
cost of pending or future litigation;
effect that acquisitions we may pursue have on our capital expenditures;
our ability to retain or attract senior management and key technical employees; and
success of strategic plans, expectations and objectives for our future operations.
Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 20142015 (the
"2014 "2015 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 19, 2015,22, 2016, and our other filings with the SEC
for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.
REFERENCES
Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture owned, until October 2014, 50% each by PDC and Lime Rock Partners, LP.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, 2015 | | December 31, 2014 | | June 30, 2016 | | December 31, 2015 |
Assets | | | | | | | | |
Current assets: | | | | | | | | |
Cash and cash equivalents | | $ | 3,690 |
| | $ | 16,066 |
| | $ | 109,099 |
| | $ | 850 |
|
Accounts receivable, net | | 106,776 |
| | 131,204 |
| | 107,350 |
| | 104,274 |
|
Fair value of derivatives | | 208,144 |
| | 187,495 |
| | 98,839 |
| | 221,659 |
|
Prepaid expenses and other current assets | | 7,683 |
| | 5,954 |
| | 3,847 |
| | 5,266 |
|
Total current assets | | 326,293 |
| | 340,719 |
| | 319,135 |
| | 332,049 |
|
Properties and equipment, net | | 1,873,327 |
| | 1,800,186 |
| | 1,930,595 |
| | 1,940,552 |
|
Assets held for sale | | 2,874 |
| | 2,874 |
| |
Fair value of derivatives | | 73,049 |
| | 112,819 |
| | 12,745 |
| | 44,387 |
|
Other assets | | 68,767 |
| | 83,990 |
| | 9,195 |
| | 53,555 |
|
Total Assets | | $ | 2,344,310 |
| | $ | 2,340,588 |
| | $ | 2,271,670 |
| | $ | 2,370,543 |
|
| | | | | | | | |
Liabilities and Shareholders' Equity | | | | | | | | |
Liabilities | | | | | | | | |
Current liabilities: | | | | | | | | |
Accounts payable | | $ | 65,337 |
| | $ | 130,321 |
| | $ | 64,234 |
| | $ | 92,613 |
|
Production tax liability | | 26,159 |
| | 21,314 |
| | 19,261 |
| | 26,524 |
|
Fair value of derivatives | | 2,245 |
| | 570 |
| | 22,824 |
| | 1,595 |
|
Funds held for distribution | | 32,780 |
| | 27,186 |
| | 49,965 |
| | 29,894 |
|
Current portion of long-term debt | | 112,063 |
| | — |
| | — |
| | 112,940 |
|
Accrued interest payable | | 19,881 |
| | 9,109 |
| | 8,557 |
| | 9,057 |
|
Deferred income taxes | | 52,188 |
| | 59,174 |
| |
Other accrued expenses | | 25,146 |
| | 62,717 |
| | 22,358 |
| | 28,709 |
|
Total current liabilities | | 335,799 |
| | 310,391 |
| | 187,199 |
| | 301,332 |
|
Long-term debt | | 550,000 |
| | 664,923 |
| | 492,997 |
| | 529,437 |
|
Deferred income taxes | | 87,907 |
| | 125,693 |
| | 41,133 |
| | 143,452 |
|
Asset retirement obligation | | 71,616 |
| | 71,992 |
| | 81,583 |
| | 84,032 |
|
Fair value of derivatives | | 723 |
| | 197 |
| | 26,830 |
| | 695 |
|
Other liabilities | | 18,529 |
| | 30,033 |
| | 17,363 |
| | 24,398 |
|
Total liabilities | | 1,064,574 |
| | 1,203,229 |
| | 847,105 |
| | 1,083,346 |
|
| | | | | | | | |
Commitments and contingent liabilities | |
| |
| |
| |
|
| | | | | | | | |
Shareholders' equity | | | | | | | | |
Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued | | — |
| | — |
| | — |
| | — |
|
Common shares - par value $0.01 per share, 150,000,000 authorized, 40,121,608 and 35,927,985 issued as of September 30, 2015 and December 31, 2014, respectively | | 401 |
| | 359 |
| |
Common shares - par value $0.01 per share, 150,000,000 authorized, 47,162,446 and 40,174,776 issued as of June 30, 2016 and December 31, 2015, respectively | | | 472 |
| | 402 |
|
Additional paid-in capital | | 903,038 |
| | 689,209 |
| | 1,211,876 |
| | 907,382 |
|
Retained earnings | | 377,400 |
| | 448,702 |
| | 213,442 |
| | 380,422 |
|
Treasury shares - at cost, 22,418 and 21,643 as of September 30, 2015 and December 31, 2014, respectively | | (1,103 | ) | | (911 | ) | |
Treasury shares - at cost, 23,822 and 20,220 as of June 30, 2016 and December 31, 2015, respectively | | | (1,225 | ) | | (1,009 | ) |
Total shareholders' equity | | 1,279,736 |
| | 1,137,359 |
| | 1,424,565 |
| | 1,287,197 |
|
Total Liabilities and Shareholders' Equity | | $ | 2,344,310 |
| | $ | 2,340,588 |
| | $ | 2,271,670 |
| | $ | 2,370,543 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
1
PDC ENERGY, INC.
Condensed Consolidated Statements of Operations
(unaudited; in thousands, except per share data)
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
Revenues | | | | | | | | | | | | | | | | |
Crude oil, natural gas and NGLs sales | | $ | 104,483 |
| | $ | 120,526 |
| | $ | 275,520 |
| | $ | 371,556 |
| | $ | 110,841 |
| | $ | 96,928 |
| | $ | 186,208 |
| | $ | 171,037 |
|
Sales from natural gas marketing | | 2,580 |
| | 13,297 |
| | 8,336 |
| | 62,649 |
| | 1,879 |
| | 2,523 |
| | 4,050 |
| | 5,756 |
|
Commodity price risk management gain, net | | 123,549 |
| | 90,213 |
| | 141,170 |
| | 12,661 |
| |
Commodity price risk management gain (loss), net | | | (92,801 | ) | | (49,041 | ) | | (81,745 | ) | | 17,621 |
|
Well operations, pipeline income and other | | 488 |
| | 520 |
| | 1,666 |
| | 1,650 |
| | 178 |
| | 550 |
| | 2,415 |
| | 1,178 |
|
Total revenues | | 231,100 |
| | 224,556 |
| | 426,692 |
| | 448,516 |
| | 20,097 |
| | 50,960 |
| | 110,928 |
| | 195,592 |
|
Costs, expenses and other | | | | | | | | | | | | | | | | |
Production costs | | 25,484 |
| | 22,754 |
| | 71,129 |
| | 64,611 |
| |
Lease operating expenses | | | 13,675 |
| | 12,639 |
| | 29,005 |
| | 28,924 |
|
Production taxes | | | 6,043 |
| | 3,837 |
| | 10,114 |
| | 7,730 |
|
Transportation, gathering and processing expenses | | | 4,465 |
| | 1,308 |
| | 8,506 |
| | 2,646 |
|
Cost of natural gas marketing | | 2,781 |
| | 13,347 |
| | 8,875 |
| | 62,645 |
| | 2,125 |
| | 2,836 |
| | 4,703 |
| | 6,094 |
|
Exploration expense | | 252 |
| | 190 |
| | 812 |
| | 773 |
| | 237 |
| | 275 |
| | 447 |
| | 560 |
|
Impairment of crude oil and natural gas properties | | 153,535 |
| | 1,863 |
| | 158,792 |
| | 3,621 |
| |
Impairment of properties and equipment | | | 4,170 |
| | 4,404 |
| | 5,171 |
| | 7,176 |
|
General and administrative expense | | 18,528 |
| | 34,625 |
| | 55,875 |
| | 96,549 |
| | 23,579 |
| | 20,728 |
| | 46,358 |
| | 41,773 |
|
Depreciation, depletion and amortization | | 80,947 |
| | 49,640 |
| | 206,873 |
| | 142,165 |
| | 107,014 |
| | 70,106 |
| | 204,402 |
| | 125,926 |
|
Provision for uncollectible notes receivable | | | — |
| | — |
| | 44,738 |
| | — |
|
Accretion of asset retirement obligations | | 1,594 |
| | 861 |
| | 4,742 |
| | 2,542 |
| | 1,811 |
| | 1,588 |
| | 3,623 |
| | 3,148 |
|
(Gain) loss on sale of properties and equipment | | (74 | ) | | 21 |
| | (302 | ) | | 577 |
| | 260 |
| | (207 | ) | | 176 |
| | (228 | ) |
Total cost, expenses and other | | 283,047 |
| | 123,301 |
| | 506,796 |
| | 373,483 |
| | 163,379 |
| | 117,514 |
| | 357,243 |
| | 223,749 |
|
Income (loss) from operations | | (51,947 | ) | | 101,255 |
| | (80,104 | ) | | 75,033 |
| |
Loss from operations | | | (143,282 | ) | | (66,554 | ) | | (246,315 | ) | | (28,157 | ) |
Interest expense | | (12,092 | ) | | (11,821 | ) | | (35,384 | ) | | (36,199 | ) | | (10,672 | ) | | (11,567 | ) | | (22,566 | ) | | (23,292 | ) |
Interest income | | 1,378 |
| | 39 |
| | 3,626 |
| | 309 |
| | 177 |
| | 1,135 |
| | 1,735 |
| | 2,248 |
|
Income (loss) from continuing operations before income taxes | | (62,661 | ) | | 89,473 |
| | (111,862 | ) | | 39,143 |
| |
Loss before income taxes | | | (153,777 | ) | | (76,986 | ) | | (267,146 | ) | | (49,201 | ) |
Provision for income taxes | | 21,167 |
| | (35,396 | ) | | 40,560 |
| | (15,852 | ) | | 58,327 |
| | 30,116 |
| | 100,166 |
| | 19,393 |
|
Income (loss) from continuing operations | | (41,494 | ) | | 54,077 |
| | (71,302 | ) | | 23,291 |
| |
Income (loss) from discontinued operations, net of tax | | — |
| | (80 | ) | | — |
| | 392 |
| |
Net income (loss) | | $ | (41,494 | ) | | $ | 53,997 |
| | $ | (71,302 | ) | | $ | 23,683 |
| |
Net loss | | | $ | (95,450 | ) | | $ | (46,870 | ) | | $ | (166,980 | ) | | $ | (29,808 | ) |
| | | | | | | | | | | | | | | | |
Earnings per share: | | | | | | | | | | | | | | | | |
Basic | | | | | | | | | | $ | (2.04 | ) | | $ | (1.17 | ) | | $ | (3.78 | ) | | $ | (0.78 | ) |
Income (loss) from continuing operations | | $ | (1.04 | ) | | $ | 1.51 |
| | $ | (1.84 | ) | | $ | 0.65 |
| |
Income (loss) from discontinued operations, net of tax | | — |
| | — |
| | — |
| | 0.01 |
| |
Net income (loss) | | $ | (1.04 | ) | | $ | 1.51 |
| | $ | (1.84 | ) | | $ | 0.66 |
| |
| | | | | | | | | |
Diluted | | | | | | | | | | $ | (2.04 | ) | | $ | (1.17 | ) | | $ | (3.78 | ) | | $ | (0.78 | ) |
Income (loss) from continuing operations | | $ | (1.04 | ) | | $ | 1.47 |
| | $ | (1.84 | ) | | $ | 0.63 |
| |
Income (loss) from discontinued operations, net of tax | | — |
| | — |
| | — |
| | 0.01 |
| |
Net income (loss) | | $ | (1.04 | ) | | $ | 1.47 |
| | $ | (1.84 | ) | | $ | 0.64 |
| |
| | | | | | | | | | | | | | | | |
Weighted-average common shares outstanding: | | | | | | | | | | | | | | | | |
Basic | | 40,085 |
| | 35,834 |
| | 38,837 |
| | 35,763 |
| | 46,742 |
| | 40,035 |
| | 44,175 |
| | 38,202 |
|
Diluted | | 40,085 |
| | 36,828 |
| | 38,837 |
| | 36,831 |
| | 46,742 |
| | 40,035 |
| | 44,175 |
| | 38,202 |
|
| | | | | | | | | | | | | | | | |
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, | | Six Months Ended June 30, |
| | 2015 | | 2014 | | 2016 | | 2015 |
Cash flows from operating activities: | | | | | | | | |
Net income (loss) | | $ | (71,302 | ) | | $ | 23,683 |
| |
Adjustments to net income (loss) to reconcile to net cash from operating activities: | | | | | |
Net loss | | | $ | (166,980 | ) | | $ | (29,808 | ) |
Adjustments to net loss to reconcile to net cash from operating activities: | | | | | |
Net change in fair value of unsettled derivatives | | 21,322 |
| | (34,323 | ) | | 201,825 |
| | 76,869 |
|
Depreciation, depletion and amortization | | 206,873 |
| | 151,293 |
| | 204,402 |
| | 125,926 |
|
Impairment of crude oil and natural gas properties | | 158,792 |
| | 4,054 |
| |
Provision for uncollectible notes receivable | | | 44,738 |
| | — |
|
Impairment of properties and equipment | | | 5,171 |
| | 7,176 |
|
Accretion of asset retirement obligation | | 4,742 |
| | 2,582 |
| | 3,623 |
| | 3,148 |
|
Stock-based compensation | | 14,278 |
| | 13,111 |
| | 11,126 |
| | 9,465 |
|
(Gain) loss on sale of properties and equipment | | (302 | ) | | 384 |
| | 176 |
| | (228 | ) |
Amortization of debt discount and issuance costs | | 5,308 |
| | 5,206 |
| | 3,077 |
| | 3,521 |
|
Deferred income taxes | | (44,770 | ) | | 14,981 |
| | (102,319 | ) | | (22,630 | ) |
Non-cash interest income | | (3,624 | ) | | — |
| | (1,194 | ) | | (2,247 | ) |
Other | | 2,241 |
| | (759 | ) | | (93 | ) | | (402 | ) |
Changes in assets and liabilities | | (10,552 | ) | | 21,753 |
| | (5,754 | ) | | (24,333 | ) |
Net cash from operating activities | | 283,006 |
| | 201,965 |
| | 197,798 |
| | 146,457 |
|
Cash flows from investing activities: | | | | | | | | |
Capital expenditures | | (489,036 | ) | | (451,081 | ) | | (235,707 | ) | | (358,135 | ) |
Proceeds from sale of properties and equipment | | 319 |
| | 1,587 |
| | 4,903 |
| | 243 |
|
Net cash from investing activities | | (488,717 | ) | | (449,494 | ) | | (230,804 | ) | | (357,892 | ) |
Cash flows from financing activities: | | | | | | | | |
Proceeds from sale of common stock, net of issuance costs | | 202,851 |
| | — |
| |
Proceeds from sale of equity, net of issuance cost | | | 296,575 |
| | 202,851 |
|
Proceeds from revolving credit facility | | 325,000 |
| | 136,750 |
| | 85,000 |
| | 272,000 |
|
Repayment of revolving credit facility | | (331,000 | ) | | (61,000 | ) | | (122,000 | ) | | (275,000 | ) |
Redemption of convertible notes | | | (115,000 | ) | | — |
|
Other | | (3,516 | ) | | (2,726 | ) | | (3,320 | ) | | (3,106 | ) |
Net cash from financing activities | | 193,335 |
| | 73,024 |
| | 141,255 |
| | 196,745 |
|
Net change in cash and cash equivalents | | (12,376 | ) | | (174,505 | ) | | 108,249 |
| | (14,690 | ) |
Cash and cash equivalents, beginning of period | | 16,066 |
| | 193,243 |
| | 850 |
| | 16,066 |
|
Cash and cash equivalents, end of period | | $ | 3,690 |
| | $ | 18,738 |
| | $ | 109,099 |
| | $ | 1,376 |
|
| | | | | | | | |
Supplemental cash flow information: | | | | | | | | |
Cash payments for: | | | | | | | | |
Interest, net of capitalized interest | | $ | 23,467 |
| | $ | 24,933 |
| | $ | 22,462 |
| | $ | 22,828 |
|
Income taxes | | 9,936 |
| | 1,800 |
| | 167 |
| | 9,936 |
|
Non-cash investing and financing activities: | | | | | | | | |
Change in accounts payable related to purchases of properties and equipment | | $ | (68,529 | ) | | $ | 19,320 |
| | $ | (28,999 | ) | | $ | (41,490 | ) |
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals | | 1,642 |
| | 500 |
| | 843 |
| | 1,395 |
|
Purchase of properties and equipment under capital leases | | 1,479 |
| | — |
| | 1,074 |
| | 950 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
3
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SeptemberJune 30, 20152016
(Unaudited)
NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION
PDC Energy, Inc. (the "Company," "we," "us," or "our") is a domestic independent exploration and production company that produces, develops, acquires and explores for crude oil, natural gas and NGLs, with primary operations in the Wattenberg Field in Colorado and the Utica Shale in southeastern Ohio. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Ohio operations are focused in the Utica Shale play. As of SeptemberJune 30, 2015,2016, we owned an interest in approximately 2,9503,000 gross wells. We are engaged in two business segments: Oil and Gas Exploration and Production and Gas Marketing. In October 2014, we sold our entire 50% ownership interest in our joint venture, PDCM, to an unrelated third-party.
The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiary Riley Natural Gas ("RNG"), and our proportionate share of our four affiliated partnerships and, for the three and nine months ended September 30, 2014, our proportionate share of PDCM.partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.
In our opinion, the accompanying condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentationstatement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2015 condensed consolidated balance sheet data was derived from audited statements, but does not include disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 20142015 Form 10-K. Our results of operations and cash flows for the three and ninesix months ended SeptemberJune 30, 20152016 are not necessarily indicative of the results to be expected for the full year or any other future period.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when (or as) each performance obligation is satisfied. In August 2015,March 2016, the FASB deferredissued an update to the effective datestandard intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations when recognizing revenue. The revenue standard tois effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.
In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard will explicitly requirerequires management to assess an entity's ability to continue as a going concern at the end of every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. We expect to adopt this standard in the fourth quarter of 2016. Adoption of this guidancestandard is not expected to have a significant impact on our condensed consolidated financial statements.
In November 2014,February 2016, the FASB issued an accounting update to accounting for derivativesaimed at increasing the transparency and hedging instruments. The update clarifies how current accounting guidance should be interpreted in evaluatingcomparability among organizations by recognizing lease assets and liabilities on the economic characteristicsbalance sheet and risksdisclosing key information about related leasing arrangements. For leases with terms of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically,more than 12 months, the accounting update clarifies thatrequires lessees to recognize an entity should consider all relevant termsasset for its right to use the underlying asset and features,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 embedded derivative feature being evaluated for bifurcation, in evaluatingpresentation of expenses and cash flows, will depend upon the natureclassification of the host contract. Furthermore, the update clarifies that no single termlease as either a finance or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument.operating lease. The assessment of the substance of the relevant terms and features should incorporate a consideration of the characteristics of the terms and features themselves, the circumstances under which the hybrid financial instrument was issued or acquired, and the potential outcomes of the hybrid financial instrument, as well as the likelihood of those potential outcomes. The accounting updateguidance is effective for public entities for fiscal years, and interim periods within those fiscal years beginning after December 15, 2015. Early2018, and interim periods within those years, with early adoption permitted, and is permitted.to be applied as of the beginning of the earliest period presented using a modified retrospective approach. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements.
In January 2015,March 2016, the FASB issued newan 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 eliminating from current accounting guidance the concept of extraordinary items, which, among other things, required an entityis effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. We expect to segregate extraordinary items considered to be unusual and infrequent from the results of ordinary operations and show the item separatelyadopt this standard in the income statement, netfourth quarter of tax, after income from continuing operations. This guidance2016. Adoption of this standard is not expected to have a significant impact on our condensed consolidated financial statements.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
In February 2015, the FASB issued an accounting update modifying existing consolidation guidance for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2015, and require either a retrospective or a modified retrospective approach to adoption. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
In April 2015, the FASB issued an accounting update simplifying the presentation of debt issuance costs and requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The update did not affect the recognition and measurement guidance for debt issuance costs. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
In July 2015, the FASB issued an accounting update requiring all entities to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
In September 2015, the FASB issued an accounting update requiring adjustments to provisional amounts that are identified during the measurement period of a business combination to be recognized in the reporting period in which the adjustment amounts are determined. The accounting update also requires an entity to present separately on the face of the income statement, or disclose in the notes, the portion of the amount recorded in current-period earnings, by line item, that would have been recorded in previous reporting periods if the adjustment to the estimated amounts had been recognized as of the acquisition date. This guidance is effective for public entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The accounting update should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.
NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS
Derivative Financial InstrumentsDetermination of Fair Value
Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:
Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.
Derivative Financial Instruments. Instruments
We measure the fair value of our derivative instruments based onupon 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 - Continued
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, 2015 | | December 31, 2014 | June 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 | 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) | (in thousands) |
Assets: | | | | | | | | | | | | | | | | | | | | | | |
Commodity-based derivative contracts | $ | 197,331 |
| | $ | 83,862 |
| | $ | 281,193 |
| | $ | 237,939 |
| | $ | 62,356 |
| | $ | 300,295 |
| $ | 74,823 |
| | $ | 36,761 |
| | $ | 111,584 |
| | $ | 174,657 |
| | $ | 91,288 |
| | $ | 265,945 |
|
Basis protection derivative contracts | — |
| | — |
| | — |
| | 19 |
| | — |
| | 19 |
| — |
| | — |
| | — |
| | 101 |
| | — |
| | 101 |
|
Total assets | 197,331 |
| | 83,862 |
| | 281,193 |
| | 237,958 |
| | 62,356 |
| | 300,314 |
| 74,823 |
| | 36,761 |
| | 111,584 |
| | 174,758 |
| | 91,288 |
| | 266,046 |
|
Liabilities: | | | | | | | | | | | | | | | | | | | | | | |
Commodity-based derivative contracts | 482 |
| | — |
| | 482 |
| | 742 |
| | — |
| | 742 |
| 38,518 |
| | 9,476 |
| | 47,994 |
| | 738 |
| | — |
| | 738 |
|
Basis protection derivative contracts | 2,486 |
| | — |
| | 2,486 |
| | 25 |
| | — |
| | 25 |
| 1,660 |
| | — |
| | 1,660 |
| | 1,552 |
| | — |
| | 1,552 |
|
Total liabilities | 2,968 |
| | — |
| | 2,968 |
| | 767 |
| | — |
| | 767 |
| 40,178 |
| | 9,476 |
| | 49,654 |
| | 2,290 |
| | — |
| | 2,290 |
|
Net asset | $ | 194,363 |
| | $ | 83,862 |
| | $ | 278,225 |
| | $ | 237,191 |
| | $ | 62,356 |
| | $ | 299,547 |
| $ | 34,645 |
| | $ | 27,285 |
| | $ | 61,930 |
| | $ | 172,468 |
| | $ | 91,288 |
| | $ | 263,756 |
|
| | | | | | | | | | | | | | | | | | | | | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
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, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in thousands) | | (in thousands) |
Fair value, net asset (liability), beginning of period | | $ | 58,256 |
| | $ | (6,967 | ) | | $ | 62,356 |
| | $ | 1,111 |
| |
Fair value, net asset beginning of period | | | $ | 73,105 |
| | $ | 74,817 |
| | $ | 91,288 |
| | $ | 62,356 |
|
Changes in fair value included in statement of operations line item: | | | | | | | | | | | | | | | | |
Commodity price risk management gain, net | | 38,085 |
| | 12,758 |
| | 42,525 |
| | 3,961 |
| |
Commodity price risk management gain (loss), net | | | (26,422 | ) | | (10,749 | ) | | (20,257 | ) | | 4,440 |
|
Sales from natural gas marketing | | 51 |
| | 2 |
| | 51 |
| | (24 | ) | | — |
| | (1 | ) | | (20 | ) | | — |
|
Settlements included in statement of operations line items: | | | | | | | | | | | | | | | | |
Commodity price risk management gain (loss), net | | (12,530 | ) | | 142 |
| | (21,063 | ) | | 882 |
| | (19,398 | ) | | (5,809 | ) | | (43,656 | ) | | (8,534 | ) |
Sales from natural gas marketing | | — |
| | (3 | ) | | (7 | ) | | 2 |
| | — |
| | (3 | ) | | (70 | ) | | (7 | ) |
Fair value, net asset end of period | | $ | 83,862 |
| | $ | 5,932 |
| | $ | 83,862 |
| | $ | 5,932 |
| | $ | 27,285 |
| | $ | 58,255 |
| | $ | 27,285 |
| | $ | 58,255 |
|
| | | | | | | | | | | | | | | | |
Net change in fair value of unsettled derivatives included in statement of operations line item: | | | | | | | | | | | | | | | | |
Commodity price risk management gain, net | | $ | 34,564 |
| | $ | 11,831 |
| | $ | 31,794 |
| | $ | 673 |
| |
Sales from natural gas marketing | | — |
| | 1 |
| | — |
| | (2 | ) | |
Total | | $ | 34,564 |
| | $ | 11,832 |
| | $ | 31,794 |
| | $ | 671 |
| |
Commodity price risk management gain (loss), net | | | $ | (18,210 | ) | | $ | (10,056 | ) | | $ | (13,105 | ) | | $ | 3,629 |
|
| | | | | | | | | | | | | | | | |
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.contracts during the periods covered by this report.
Non-Derivative Financial Assets and Liabilities
The carrying value of the financial instruments included in current assets and current liabilities excluding the current portion of long-term debt, approximate fair value due to the short-term maturities of these instruments.
We utilize fair value on a nonrecurring basis to review our crude oil and natural gas properties for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold.
The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. The liability related to this plan, which was included in other liabilities on the condensed consolidated balance sheets, was immaterial as of SeptemberJune 30, 20152016 and December 31, 2014.2015.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
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 SeptemberJune 30, 20152016, we estimate the fair value of the portion of our long-term debt related to our 3.25% convertible senior notes due 2016 to be $161.4 million, or 140.3% of par value, and the portion related to our 7.75% senior notes due 2022 to be $496.3$521.3 million, or 99.3%104.3% 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 as it representsdue to the present valuevariable nature of future lease payments.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 SeptemberJune 30, 2015,2016, taking into account the estimated likelihood of nonperformance.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents the counterparties that expose us to credit risk as of SeptemberJune 30, 20152016 with regard to our derivative assets:
| | Counterparty Name | | Fair Value of Derivative Assets | | Fair Value of Derivative Assets |
| | (in thousands) | | (in thousands) |
Canadian Imperial Bank of Commerce (1) | | | $ | 33,559 |
|
JP Morgan Chase Bank, N.A (1) | | $ | 77,743 |
| | 29,011 |
|
Canadian Imperial Bank of Commerce (1) | | 72,977 |
| |
Bank of Nova Scotia (1) | | 41,354 |
| | 22,676 |
|
Wells Fargo Bank, N.A. (1) | | 38,973 |
| | 13,351 |
|
NATIXIS (1) | | 32,941 |
| | 10,418 |
|
Key Bank N.A. (1)
| | 11,163 |
| |
Other lenders in our revolving credit facility | | 6,042 |
| | 2,329 |
|
Various (2) | | | 240 |
|
Total | | $ | 281,193 |
| | $ | 111,584 |
|
| | | | |
__________
(1)Major lender in our revolving credit facility. See Note 7, Long-Term Debt.
(2)Represents a total of six counterparties.
NoteNotes Receivable. The following table presents information regarding oura note receivable outstanding as of SeptemberJune 30, 2015:2016:
| | | Amount | Amount |
| (in thousands) | (in thousands) |
Note receivable: | | |
Principal outstanding, December 31, 2014 | $ | 39,707 |
| |
Principal outstanding, December 31, 2015 | | $ | 43,069 |
|
Paid-in-kind interest | 2,430 |
| 969 |
|
Principal outstanding, September 30, 2015 | $ | 42,137 |
| |
Principal outstanding, June 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. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the sale. As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39.0 million, bearing interest at varying rates beginning at 8%, and increasing annually. Pursuant to the Note agreement, interest shall be paidis payable quarterly, in arrears, commencing in December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. As of SeptemberJune 30, 20152016, the issuer of the Note had elected the PIK Interest option. The principal and any unpaid interest shall beis due and payable in full in September 2020 and can be prepaid in whole or in part at any time and in certain circumstanceswithout premium or penalty. If an event of default occurs under the Note agreement, the Note must be repaid prior to maturity. Any such prepayment will be made without premium or penalty. The Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets.
On a quarterly basis, we examine the Note for evidence of impairment, evaluating factors such as the creditworthiness of the issuer of the Note and the value of the underlying assets that secure the Note. We performed our quarterly evaluation and cash flow analysis 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 $44.0 million outstanding balance as of March 31, 2016, which was included in the condensed consolidated balance sheet line item other assets.
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 $1.0 million was PIK Interest, and we recognized $1.1 million and $2.2 million of interest income related to the Note for the three and six months ended June 30, 2015, respectively, of which $0.8 million and $1.6 million, respectively, was PIK Interest.
Additionally, we recorded a $0.7 million provision and allowance for uncollectible notes receivable to impair a promissory note related to a previous divestiture as collection of the promissory note is not reasonably assured based on the analysis we performed as of March 31, 2016.
As of June 30, 2016, there has been no change to our assessment of the collectibility of the notes or related interest since March 31, 2016.
Commencing in the second quarter of 2016, we have ceased recognizing interest income on the notes and are accounting for the notes under the cash basis method.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
Under the effective interest method, we recognized $1.1 million and $3.4 million of interest income for the three and nine months ended September 30, 2015, respectively, of which $0.8 million and $2.4 million, respectively, was PIK Interest. As of September 30, 2015, the $42.1 million outstanding balance on the Note was included in the condensed consolidated balance sheet line item other assets.
NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS
Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas, we utilize the following economic hedging strategies for each of our business segments.
For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and
For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative.
We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of SeptemberJune 30, 20152016, we had derivative instruments, which were comprised of collars, fixed-price swaps, basis protection swaps and physical sales and purchases, in place for a portion of our anticipated production through 2018 for a total of 73,17671,560 BBtu of natural gas and 6,7019,214 MBbls of crude oil. The majority of our derivative contracts are entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices.
We have not elected not to designate any of our derivative instruments as hedges, and therefore do not qualify for use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
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: | | Balance sheet line item | | September 30, 2015 | | December 31, 2014 | Derivative instruments: | | Balance sheet line item | | June 30, 2016 | | December 31, 2015 |
| | (in thousands) | | (in thousands) |
Derivative assets: | Current | | | | | Current | | | | |
| | Commodity contracts | | | | |
| | Related to crude oil and natural gas sales | | Fair value of derivatives | | $ | 98,526 |
| | $ | 221,161 |
|
| Commodity contracts | | | | | Related to natural gas marketing | | Fair value of derivatives | | 313 |
| | 441 |
|
| Related to crude oil and natural gas sales | | Fair value of derivatives | | $ | 207,731 |
| | $ | 186,886 |
| Basis protection contracts | | | | |
| Related to natural gas marketing | | Fair value of derivatives | | 413 |
| | 590 |
| Related to crude oil and natural gas sales | | Fair value of derivatives | | — |
| | 57 |
|
| Basis protection contracts | | | | | | 98,839 |
| | 221,659 |
|
| Related to crude oil and natural gas sales | | Fair value of derivatives | | — |
| | 19 |
| Non-current | | | | |
| | 208,144 |
| | 187,495 |
| Commodity contracts | | | | |
| Non-current | | | | | Related to crude oil and natural gas sales | | Fair value of derivatives | | 12,673 |
| | 44,292 |
|
| Commodity contracts | | | | | Related to natural gas marketing | | Fair value of derivatives | | 72 |
| | 51 |
|
| Related to crude oil and natural gas sales | | Fair value of derivatives | | 72,950 |
| | 112,599 |
| Basis protection contracts | | | | |
| Related to natural gas marketing | | Fair value of derivatives | | 99 |
| | 220 |
| Related to crude oil and natural gas sales | | Fair value of derivatives | | — |
| | 44 |
|
| | 73,049 |
| | 112,819 |
| | 12,745 |
| | 44,387 |
|
Total derivative assets | | $ | 281,193 |
| | $ | 300,314 |
| | $ | 111,584 |
| | $ | 266,046 |
|
| | | | | | | | |
Derivative liabilities: | Current | | | | | Current | | | | |
| Commodity contracts | | | | | Commodity contracts | | | | |
| Related to natural gas marketing | | Fair value of derivatives | | $ | 393 |
| | $ | 545 |
| Related to crude oil and natural gas sales | | Fair value of derivatives | | $ | 21,179 |
| | $ | — |
|
| Basis protection contracts | | | | | Related to natural gas marketing | | Fair value of derivatives | | 251 |
| | 417 |
|
| Related to crude oil and natural gas sales | | Fair value of derivatives | | 1,852 |
| | 25 |
| Basis protection contracts | | | | |
| | 2,245 |
| | 570 |
| Related to crude oil and natural gas sales | | Fair value of derivatives | | 1,394 |
| | 1,178 |
|
| Non-current | | | | | | 22,824 |
| | 1,595 |
|
| Commodity contracts | | | | | Non-current | | | | |
| Related to natural gas marketing | | Fair value of derivatives | | 89 |
| | 197 |
| Commodity contracts | | | | |
| Basis protection contracts | | | | | Related to crude oil and natural gas sales | | Fair value of derivatives | | 26,509 |
| | 275 |
|
| Related to crude oil and natural gas sales | | Fair value of derivatives | | 634 |
| | — |
| Related to natural gas marketing | | Fair value of derivatives | | 54 |
| | 46 |
|
| | 723 |
| | 197 |
| Basis protection contracts | | | | |
| | Related to crude oil and natural gas sales | | Fair value of derivatives | | 267 |
| | 374 |
|
| | | 26,830 |
| | 695 |
|
Total derivative liabilities | | $ | 2,968 |
| | $ | 767 |
| | $ | 49,654 |
| | $ | 2,290 |
|
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 June 30, | | Six Months Ended June 30, |
Condensed consolidated statement of operations line item | | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in thousands) | | (in thousands) |
Commodity price risk management gain, net | | | | | | | | | |
Commodity price risk management gain (loss), net | | | | | | | | | |
Net settlements | | $ | 67,993 |
| | $ | (4,459 | ) | | $ | 162,454 |
| | $ | (21,511 | ) | | $ | 53,301 |
| | $ | 44,049 |
| | $ | 120,132 |
| | $ | 94,461 |
|
Net change in fair value of unsettled derivatives | | 55,556 |
| | 94,672 |
| | (21,284 | ) | | 34,172 |
| | (146,102 | ) | | (93,090 | ) | | (201,877 | ) | | (76,840 | ) |
Total commodity price risk management gain, net | | $ | 123,549 |
| | $ | 90,213 |
| | $ | 141,170 |
| | $ | 12,661 |
| |
Total commodity price risk management gain (loss), net | | | $ | (92,801 | ) | | $ | (49,041 | ) | | $ | (81,745 | ) | | $ | 17,621 |
|
Sales from natural gas marketing | | | | | | | | | | | | | | | | |
Net settlements | | $ | 165 |
| | $ | 210 |
| | $ | 561 |
| | $ | (376 | ) | | $ | 53 |
| | $ | 165 |
| | $ | 298 |
| | $ | 396 |
|
Net change in fair value of unsettled derivatives | | (5 | ) | | 170 |
| | (298 | ) | | 123 |
| | (299 | ) | | (124 | ) | | (519 | ) | | (293 | ) |
Total sales from natural gas marketing | | $ | 160 |
| | $ | 380 |
| | $ | 263 |
| | $ | (253 | ) | | $ | (246 | ) | | $ | 41 |
| | $ | (221 | ) | | $ | 103 |
|
Cost of natural gas marketing | | | | | | | | | | | | | | | | |
Net settlements | | $ | (157 | ) | | $ | (182 | ) | | $ | (531 | ) | | $ | 502 |
| | $ | (49 | ) | | $ | (157 | ) | | $ | (277 | ) | | $ | (375 | ) |
Net change in fair value of unsettled derivatives | | (5 | ) | | (191 | ) | | 260 |
| | (199 | ) | | 346 |
| | 115 |
| | 571 |
| | 264 |
|
Total cost of natural gas marketing | | $ | (162 | ) | | $ | (373 | ) | | $ | (271 | ) | | $ | 303 |
| | $ | 297 |
| | $ | (42 | ) | | $ | 294 |
| | $ | (111 | ) |
| | | | | | | | | | | | | | | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
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, 2015 | | Derivative instruments, recorded in condensed consolidated balance sheet, gross | | Effect of master netting agreements | | Derivative instruments, net | |
As of June 30, 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 | | $ | 281,193 |
| | $ | (2,548 | ) | | $ | 278,645 |
| | $ | 111,584 |
| | $ | (30,404 | ) | | $ | 81,180 |
|
| | | | | | | | | | | | |
Liability derivatives: | | | | | | | | | | | | |
Derivative instruments, at fair value | | $ | 2,968 |
| | $ | (2,548 | ) | | $ | 420 |
| | $ | 49,654 |
| | $ | (30,404 | ) | | $ | 19,250 |
|
| | | | | | | | | | | | |
| | As of December 31, 2014 | | Derivative instruments, recorded in condensed consolidated balance sheet, gross | | Effect of master netting agreements | | Derivative instruments, net | |
As of December 31, 2015 | | | 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 | | $ | 300,314 |
| | $ | (29 | ) | | $ | 300,285 |
| | $ | 266,046 |
| | $ | (1,921 | ) | | $ | 264,125 |
|
| | | | | | | | | | | | |
Liability derivatives: | | | | | | | | | | | | |
Derivative instruments, at fair value | | $ | 767 |
| | $ | (29 | ) | | $ | 738 |
| | $ | 2,290 |
| | $ | (1,921 | ) | | $ | 369 |
|
| | | | | | | | | | | | |
NOTE 5 - PROPERTIES AND EQUIPMENT
The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization ("DD&A"):
| | | September 30, 2015 | | December 31, 2014 | June 30, 2016 | | December 31, 2015 |
| (in thousands) | (in thousands) |
Properties and equipment, net: | | | | | | |
Crude oil and natural gas properties | | | | | | |
Proved | $ | 2,712,759 |
| | $ | 2,267,165 |
| $ | 3,067,916 |
| | $ | 2,881,189 |
|
Unproved | 82,280 |
| | 188,206 |
| 61,202 |
| | 60,498 |
|
Total crude oil and natural gas properties | 2,795,039 |
| | 2,455,371 |
| 3,129,118 |
| | 2,941,687 |
|
Equipment and other | 32,119 |
| | 29,562 |
| 31,566 |
| | 30,098 |
|
Land and buildings | 9,016 |
| | 9,015 |
| 9,040 |
| | 12,667 |
|
Construction in progress | 99,008 |
| | 137,937 |
| 117,190 |
| | 113,115 |
|
Properties and equipment, at cost | 2,935,182 |
| | 2,631,885 |
| 3,286,914 |
| | 3,097,567 |
|
Accumulated DD&A | (1,061,855 | ) | | (831,699 | ) | (1,356,319 | ) | | (1,157,015 | ) |
Properties and equipment, net | $ | 1,873,327 |
| | $ | 1,800,186 |
| $ | 1,930,595 |
| | $ | 1,940,552 |
|
| | | | | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents impairment charges recorded for crude oil and natural gas properties:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in thousands) |
Continuing operations: | | | | | | | |
Impairment of proved and unproved properties | $ | 150,344 |
| | $ | — |
| | $ | 150,344 |
| | $ | — |
|
Amortization of individually insignificant unproved properties | 3,191 |
| | 1,085 |
| | 8,448 |
| | 2,843 |
|
Other | — |
| | 778 |
| | — |
| | 778 |
|
Total continuing operations | 153,535 |
| | 1,863 |
| | 158,792 |
| | 3,621 |
|
Discontinued operations: | | | | | | | |
Amortization of individually insignificant unproved properties | — |
| | 274 |
| | — |
| | 433 |
|
Total impairment of crude oil and natural gas properties | $ | 153,535 |
| | $ | 2,137 |
| | $ | 158,792 |
| | $ | 4,054 |
|
| | | | | | | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) |
| | | | | | | |
Impairment of proved and unproved properties | $ | 1,084 |
| | $ | 1,631 |
| | $ | 2,053 |
| | $ | 1,919 |
|
Amortization of individually insignificant unproved properties | 54 |
| | 2,773 |
| | 86 |
| | 5,257 |
|
Impairment of crude oil and natural gas properties
| 1,138 |
| | 4,404 |
| | 2,139 |
| | 7,176 |
|
Land and buildings | 3,032 |
| | — |
| | 3,032 |
| | — |
|
Impairment of properties and equipment | $ | 4,170 |
| | $ | 4,404 |
| | $ | 5,171 |
| | $ | 7,176 |
|
Due to a significant decline in commodity prices and a decrease in net-back realizations, we experienced a triggering event that required us to assess our crude oil and natural gas properties for possible impairment during the third quarter of 2015. As a result of our assessment, we recorded an impairment charge 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. This impairment charge represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value of approximately $27.9 million, excluding estimated salvage value, was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. Additionally, as a result of the current outlook for future commodity prices, 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. These impairment charges were included in the condensed consolidated statements of operations line item impairment of crude oil and natural gas properties.
NOTE 6 - INCOME TAXES
We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. A tax expense or benefit unrelated to the current year income or loss is recognized in its entirety as a discrete item of tax in the period identified. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.
The effective tax rate for continuing operationsthe three and six months ended June 30, 2016 was a 37.9% and 37.5% benefit on loss compared to a 39.1% and 39.4% benefit on loss for the three and ninesix months ended SeptemberJune 30, 2015 was a 33.8% and 36.3% benefit on loss, respectively, compared to a 39.6% and 40.5% provision on income for the three and nine months ended September 30, 2014, respectively.
2015. The effective tax rates for the three and nine months ended September 30, 2015 include discrete tax expense of $0.3 million. This discrete tax expense arose based upon the final actual 2014 tax return expense differing from the previous year’s estimated tax provision amount and the loss of a state deferred tax asset due to ceasing operations within that state. The effective rate for the three and ninesix months ended SeptemberJune 30, 2015 would have been 34.2% and 36.5%, respectively, without the inclusion of discrete items. This effective rate2016 is based upon a full year forecasted tax benefit on loss and is greater than the statutory federal tax rate, primarily due to state taxes and percentage depletion, and domestic production deduction, partially offset by nondeductible expenses that consist primarily of officers'officers’ compensation and governmentnondeductible lobbying expenses.
The effective tax rates for the three and nine months ended September 30, 2014 include discrete tax expense of $0.6 million. This discrete tax expense arose based upon the final actual 2013 tax return expense differing from the previous year’s estimated tax provision amount. The effective rate for the three and ninesix months ended SeptemberJune 30, 2014 would have been 38.8% and 38.9%, respectively, without the inclusion of discrete items. This effective tax rate is based upon a full year forecasted tax provision on income and is greater than2015 differs from the statutory rate primarily due to state taxes and nondeductible officers' compensation, partially offset by percentage depletion and domestic production deduction. There were no significant discrete items recorded during the three and six months ended June 30, 2016 or June 30, 2015.
As of SeptemberJune 30, 2015, we had2016, 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 voluntary participationto voluntarily participate in the Internal Revenue Service’sService's ("IRS") Compliance Assurance Program for the 20142015 and 20152016 tax years. WeWith respect to the 2014 tax year, we have receivedagreed to a partial acceptance “no change” notice frompost filing adjustment with the IRS which resulted in an immaterial tax payment for our filedthe 2014 tax year. The IRS has fully accepted the 2014 federal tax return, and expect to receive a full acceptance notice after the IRS’s post filing review is completed.as adjusted.
NOTE 7 - LONG-TERM DEBT
Long-term debt consisted of the following as of:
|
| | | | | | | |
| June 30, 2016 | | December 31, 2015 |
| (in thousands) |
Senior notes: | | | |
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 discount and unamortized debt issuance costs | — |
| | 112,940 |
|
| | | |
7.75% Senior notes due 2022: | | | |
Principal amount | 500,000 |
| | 500,000 |
|
Unamortized debt issuance costs | (7,003 | ) | | (7,563 | ) |
7.75% Senior notes due 2022, net of unamortized debt issuance costs | 492,997 |
| | 492,437 |
|
Total senior notes | 492,997 |
| | 605,377 |
|
| | | |
Revolving credit facility | — |
| | 37,000 |
|
Total debt, net of discount and unamortized debt issuance costs | 492,997 |
| | 642,377 |
|
Less current portion of long-term debt | — |
| | 112,940 |
|
Long-term debt | $ | 492,997 |
| | $ | 529,437 |
|
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 7 - LONG-TERM DEBT
Long-term debt consists of the following:
|
| | | | | | | |
| September 30, 2015 | | December 31, 2014 |
| (in thousands) |
Senior notes: | | | |
3.25% Convertible senior notes due 2016: | | | |
Principal amount | $ | 115,000 |
| | $ | 115,000 |
|
Unamortized discount | (2,937 | ) | | (6,077 | ) |
3.25% Convertible senior notes due 2016, net of discount | 112,063 |
| | 108,923 |
|
7.75% Senior notes due 2022 | 500,000 |
| | 500,000 |
|
Total senior notes | 612,063 |
| | 608,923 |
|
| | | |
Revolving credit facility | 50,000 |
| | 56,000 |
|
Total debt | 662,063 |
| | 664,923 |
|
Less current portion of long-term debt | 112,063 |
| | — |
|
Long-term debt | $ | 550,000 |
| | $ | 664,923 |
|
Senior Notes
3.25% Convertible Senior Notes Due 2016. In November 2010, we issued $115 million aggregate principal amount of 3.25% convertible senior notes due May 15, 2016 (the "Convertible Notes") in a private placement to qualified institutional buyers. Interest is payable semi-annually in arrears on eachThe maturity for the payment of principal was May 15, and November 15. The indenture governing the Convertible Notes contains certain non-financial covenants. We allocated the gross proceeds of the Convertible Notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based upon the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued2016. At December 31, 2015, our indebtedness included the Convertible Notes. The original issue discount and capitalized debt issuance costs are being amortized to interest expense over the life of the Convertible Notes using an effective interest rate of 7.4%. As the stated maturity for payment of principal isUpon settlement in May 2016, we have includedpaid the carrying value of the Convertible Notes, net of discount, in the current portion of long-term debt on our condensed consolidated balance sheet as of September 30, 2015.
Upon conversion, the Convertible Notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. Per the terms of the Convertible Notes, we have currently elected the net-settlement method to satisfy our conversion obligation, which allows us to settle theaggregate principal amount of the Convertible Notes, inplus cash and to settlefor fractional shares, totaling approximately $115.0 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 in shares, as well as cash in lieu of fractional shares.value. See Note 11, The Convertible Notes were not convertible at the option of holders as of September 30, 2015. Notwithstanding the inability to convert, the “if-converted” value of the Convertible Notes as of September 30, 2015 exceeded the aggregate principal amount by approximately $28.8 million.Common Stock, for more information.
7.75% Senior Notes Due 2022. 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 to qualified institutional buyers. Interest on theThe 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on each April 15 and October 15.15. The indenture governing the 2022 Senior Notes contains customary restrictive incurrence covenants. Capitalized debt issuance costs are being amortized as interest expense over the life of the 2022 Senior Notes using the effective interest method.
As of SeptemberJune 30, 2015,2016, we were in compliance with all covenants related to the Convertible Notes and the 2022 Senior Notes and expect to remain in compliance throughout the next 12-month period.
Credit Facility
Revolving Credit Facility. In September 2015, we entered intoWe are party to a Second Amendment to Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent, and other lenders party thereto. This agreement amends and restatesthereto (sometimes referred to as the "revolving credit agreement dated November 2010 and extends the maturity of thefacility"). The revolving credit facility tomatures in May 2020. The revolving credit facility2020 and is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base. AsIn May 2016, we completed the semi-annual redetermination of September 30, 2015,our revolving credit facility by the fall 2015 semi-annual redeterminationlenders, which resulted in the reaffirmation of our borrowing base at $700 million; however, we have elected to maintain the aggregate commitment at $450 million. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets.properties. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
We had $50.0 millionno outstanding balance on our revolving credit facility as of SeptemberJune 30, 2015,2016, compared to $56.0$37.0 million outstanding as of December 31, 2014.2015. The weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.7% and 4.1%2.6% per annum as of September 30, 2015 and December 31, 2014, respectively.2015.
As of SeptemberJune 30, 20152016, RNG had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit currently expires in September 2016 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal to the letter of credit. As of SeptemberJune 30, 2015,2016, the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $388.3$438.3 million. In addition to our currently elected commitment of $450 million, we have an additional $250 million of borrowing base availability under the revolving credit facility, subject to certain terms and conditions of the agreement.
The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00. As of SeptemberJune 30, 2015,2016, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 8 - CAPITAL LEASES
Beginning in the first quarter of 2015, we enteredWe periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. Each lease agreement has a term of three years and isThese leases are being accounted for as a capital lease,leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90% of the fair value of the leased vehicles at inception of the lease.
The following table presents leased vehicles under capital leases as of SeptemberJune 30, 2015:2016:
| |
| | Amount | | Amount |
| | (in thousands) | | (in thousands) |
Vehicles | | $ | 1,479 |
| | $ | 2,674 |
|
Accumulated depreciation | | (121 | ) | | (464 | ) |
| | $ | 1,358 |
| | $ | 2,210 |
|
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 June 30, | | | Amount |
| | (in thousands) | | (in thousands) |
2016 | | $ | 447 |
| |
2017 | | 454 |
| | $ | 820 |
|
2018 | | 743 |
| | 1,075 |
|
2019 | | | 734 |
|
| | 1,644 |
| | 2,629 |
|
Less executory cost | | (72 | ) | | (105 | ) |
Less amount representing interest | | (215 | ) | | (305 | ) |
Present value of minimum lease payments | | $ | 1,357 |
| | $ | 2,219 |
|
| | |
| | |
|
Short-term capital lease obligations | | $ | 315 |
| | $ | 606 |
|
Long-term capital lease obligations | | 1,042 |
| | 1,613 |
|
| | $ | 1,357 |
| | $ | 2,219 |
|
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 - Continued
NOTE 9 - ASSET RETIREMENT OBLIGATIONS
The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties:
| | | Amount | Amount |
| (in thousands) | (in thousands) |
| | |
Balance at beginning of period, January 1, 2015 | $ | 73,855 |
| |
Balance at beginning of period, January 1, 2016 | | $ | 89,492 |
|
Obligations incurred with development activities | 1,642 |
| 843 |
|
Accretion expense | 4,742 |
| 3,623 |
|
Obligations discharged with asset retirements | (3,163 | ) | |
Balance end of period, September 30, 2015 | 77,076 |
| |
Obligations discharged with disposal of properties and asset retirements | | (5,475 | ) |
Balance end of period, June 30, 2016 | | 88,483 |
|
Less current portion | (5,460 | ) | (6,900 | ) |
Long-term portion | $ | 71,616 |
| $ | 81,583 |
|
| | |
Our estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging and abandonment cost considering federal and state regulatory requirements in effect. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2016, the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 7.6% to 8.0%. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
original estimate of undiscounted cash flows or changes in inflation factors and changes to our credit-adjusted risk-free rate as market conditions warrant. Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales and processing agreements on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. As commoditynatural gas prices continue to remain depressed, certain customersthird-party producers under our Gas Marketing segment have begun and will continue to experience financial distress, which has led to certain contractual defaults. Todefaults and litigation; however, to date, we have had no material counterparty default losses. As of June 30, 2016, we have recorded an allowance for doubtful accounts of approximately $0.9 million. We have initiated several legal actions for breach of contract, collection, and related claims against certain third-party producers that are delinquent in their payment obligations, which have to date resulted in one default judgment. There have been no collections received to date and and some of the third-party producers have shut-in their wells.
A group of independent West Virginia natural gas producers has filed, but not served on RNG, a complaint 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 is aware of this lawsuit filing but has not received formal service of process which commences the litigation against RNG. Furthermore, 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.
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 June 30, | | | |
Area | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 and Through Expiration | | Total | | Expiration Date | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 and Through Expiration | | Total | | Expiration Date |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas (MMcf) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Appalachian Basin | | 7,136 |
| | 7,117 |
| | 7,117 |
| | 7,117 |
| | 20,480 |
| | 48,967 |
| | August 31, 2022 | |
Gas Marketing segment | | | 7,117 |
| | 7,117 |
| | 7,117 |
| | 7,136 |
| | 15,138 |
| | 43,625 |
| | August 31, 2022 |
Utica Shale | | 2,745 |
| | 2,738 |
| | 2,737 |
| | 2,738 |
| | 10,500 |
| | 21,458 |
| | July 22, 2023 | | 2,738 |
| | 2,738 |
| | 2,738 |
| | 2,745 |
| | 8,444 |
| | 19,403 |
| | July 22, 2023 |
Total | | 9,881 |
| | 9,855 |
| | 9,854 |
| | 9,855 |
| | 30,980 |
| | 70,425 |
| | | 9,855 |
| | 9,855 |
| | 9,855 |
| | 9,881 |
| | 23,582 |
| | 63,028 |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Crude oil (MBbls) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | 2,420 |
| | 2,413 |
| | 2,413 |
| | 2,413 |
| | 1,813 |
| | 11,472 |
| | June 30, 2020 | | 2,413 |
| | 2,413 |
| | 2,413 |
| | 2,421 |
| | — |
| | 9,660 |
| | June 30, 2020 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Dollar commitment (in thousands) | | $ | 17,623 |
| | $ | 17,473 |
| | $ | 16,326 |
| | $ | 16,326 |
| | $ | 21,312 |
| | $ | 89,060 |
| | | $ | 17,573 |
| | $ | 16,536 |
| | $ | 16,324 |
| | $ | 16,369 |
| | $ | 9,052 |
| | $ | 75,854 |
| |
Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.
Class Action Regarding 2010 and 2011 Partnership Purchases
In December 2011, the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of unit holders of 12 former limited partnerships, related to its repurchase of the 12 partnerships, which were formed beginning in late 2002 through 2005. The mergers were completed in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and was titled Schulein v. Petroleum Development Corp. The complaint primarily alleged that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In January 2014, the plaintiffs were certified as a class by the court.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
In October 2014, the Company and plaintiffs’ counsel reached a settlement agreement. That settlement agreement was signed in December 2014 and was given final court approval in March 2015. Under this settlement agreement, the plaintiffs received a cash payment of $37.5 million in January 2015, of which the Company paid $31.5 million and insurers paid $6 million. In March 2015, the class action was dismissed with prejudice and all class claims were released. As of December 31, 2014, the Company accrued a liability of $37.5 million related to this litigation, which was included in other accrued expenses in the condensed consolidated balance sheet.
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 that require remediation are probable to require remediation and the costs can be reasonably estimated. As of SeptemberJune 30, 20152016 and December 31, 2014,2015, we had accrued environmental liabilities in the amount of $4.4$4.0 million and $0.8$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 SeptemberJune 30, 20152016 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown past non-compliance with environmental laws will not be discovered on our properties.
In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the United StatesU.S. Environmental Protection Agency ("EPA"). The Information Request seeks,sought, among other things, information related to the design, operation, and maintenance of our production facilities in the DJDenver-Julesburg Basin of Colorado. The Information Request focuses primarilyfocused on historical operation and design information for 46 of our production facilities and asks that we conduct certain sampling and analyses at the identified 46 facilities. We are currently scheduledresponded to respond to
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
the Information Request in January 2016. We continue to meet with the EPA and provide additional information, but cannot predict the outcome of this matter at this time.
In 2014,addition, in December 2015, we experiencedreceived a lossCompliance Advisory pursuant to C.R.S. § 25-7-115(2) from the Colorado Department of well control while drilling an oilPublic Health and gas wellEnvironment'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 in Morgan County, Ohio. The event resulted in a releasethe process of well fluids, including oil based drilling mud. We have completedresponding to the appropriate remediation to addressadvisory, and working with the release. In August 2015,agency on specific response processes, but cannot predict the EPA issued us a Noticeoutcome of Intent seeking civil penalties. We and the EPA recently agreed in principle to settle this matter for a civil fine of approximately $152,000, although settlement is subject to the parties entering into a definitive settlement agreement.at this time.
Employment Agreements with Executive Officers. Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company.
NOTE 11 - COMMON STOCK
Sale of Equity Securities
In March 2016, we completed a public offering of 5,922,500 shares of our common stock, par value $0.01 per share, at a price to us of $50.11 per share. Net proceeds of the offering were $296.6 million, after deducting offering expenses and underwriting discounts, of which $59,225 is included in common shares-par value and $296.5 million is included in additional paid-in capital ("APIC") on the June 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. Upon maturity of our Convertible Notes in May 2016, we paid the aggregate principal amount, plus cash for fractional shares, totaling approximately $115.0 million, utilizing proceeds from the offering. Additionally, we issued 792,406 shares of common stock for the premium in excess of the conversion price of $42.40 per share.
In March 2015, we completed a public offering of 4,002,000 shares of our common stock, par value $0.01 per share, at a price to us of $50.73 per share. Net proceeds of the offering were $202.9 million, after deducting offering expenses and underwriting discounts, of which $40,020 is included in common shares-par value and $202.8 million is included in additional paid-in capitalAPIC on the September 30, 2015 condensed consolidated balance sheet.sheets. The shares were issued pursuant to anthe 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 June 30, | | Six Months Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (in thousands) | | (in thousands) |
| | | | | | | | | | | | | | | | |
Stock-based compensation expense | | $ | 4,813 |
| | $ | 4,232 |
| | $ | 14,278 |
| | $ | 13,111 |
| | $ | 6,444 |
| | $ | 5,097 |
| | $ | 11,126 |
| | $ | 9,465 |
|
Income tax benefit | | (1,828 | ) | | (1,482 | ) | | (5,423 | ) | | (4,856 | ) | | (2,452 | ) | | (1,936 | ) | | (4,233 | ) | | (3,595 | ) |
Net stock-based compensation expense | | $ | 2,985 |
| | $ | 2,750 |
| | $ | 8,855 |
| | $ | 8,255 |
| | $ | 3,992 |
| | $ | 3,161 |
| | $ | 6,893 |
| | $ | 5,870 |
|
| | | | | | | | | | | | | | | | |
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 - Continued
In January 2015,2016, the Compensation Committee awarded 68,27458,709 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:
| | | Nine Months Ended September 30, | Six Months Ended June 30, |
| 2015 | | 2014 | 2016 | | 2015 |
| | | | | | |
Expected term of award | 6 years |
| | 6 years |
| 6.0 years |
| | 5.2 years |
|
Risk-free interest rate | 1.6 | % | | 2.1 | % | 1.8 | % | | 1.4 | % |
Expected volatility | 59.4 | % | | 65.6 | % | 54.5 | % | | 58.0 | % |
Weighted-average grant date fair value per share | $ | 21.99 |
| | $ | 29.96 |
| $ | 26.96 |
| | $ | 22.23 |
|
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
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 theall periods presented:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2015 | | 2014 |
| 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, | 279,011 |
| | $ | 38.77 |
| | | | | | 190,763 |
| | $ | 33.77 |
| | | | |
Awarded | 68,274 |
| | 39.63 |
| | | | | | 88,248 |
| | 49.57 |
| | | | |
Outstanding at September 30, | 347,285 |
| | 38.94 |
| | 7.5 | | $ | 4,888 |
| | 279,011 |
| | 38.77 |
| | 8.0 | | $ | 3,215 |
|
Vested and expected to vest at September 30, | 341,423 |
| | 38.89 |
| | 7.5 | | 4,821 |
| | 270,589 |
| | 38.56 |
| | 8.0 | | 3,173 |
|
Exercisable at September 30, | 191,149 |
| | 35.68 |
| | 6.6 | | 3,312 |
| | 109,920 |
| | 32.71 |
| | 7.1 | | 1,933 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 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 | (114,853 | ) | | 38.71 |
| | | | $ | 2,488 |
| | — |
| | — |
| | | | |
Outstanding at June 30, | 270,309 |
| | 41.86 |
| | 7.4 | | 4,258 |
| | 347,285 |
| | 38.94 |
| | 7.8 | | $ | 5,107 |
|
Vested and expected to vest at June 30, | 263,546 |
| | 41.70 |
| | 7.4 | | 4,193 |
| | 339,980 |
| | 38.88 |
| | 7.7 | | 5,019 |
|
Exercisable at June 30, | 162,895 |
| | 38.31 |
| | 6.4 | | 3,144 |
| | 191,149 |
| | 35.68 |
| | 6.9 | | 3,433 |
|
Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our condensed consolidated statement of operations as of SeptemberJune 30, 20152016 was $2.4$2.0 million. The cost is expected to be recognized over a weighted-average period of 1.72.1 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 2015,2016, the Compensation Committee awarded to our executive officers a total of 80,70761,634 time-based restricted shares that vest ratably over a three-year period ending in January 2018.2019.
The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the ninesix months ended SeptemberJune 30, 20152016:
| | | Shares | | Weighted-Average Grant-Date Fair Value | Shares | | Weighted-Average Grant Date Fair Value |
| | | | | | |
Non-vested at December 31, 2014 | 564,332 |
| | $ | 46.02 |
| |
Non-vested at December 31, 2015 | | 525,081 |
| | $ | 50.23 |
|
Granted | 295,694 |
| | 48.58 |
| 267,379 |
| | 57.11 |
|
Vested | (258,555 | ) | | 40.36 |
| (233,269 | ) | | 49.74 |
|
Forfeited | (17,457 | ) | | 54.51 |
| (12,306 | ) | | 55.27 |
|
Non-vested at September 30, 2015 | 584,014 |
| | 49.56 |
| |
Non-vested at June 30, 2016 | | 546,885 |
| | 53.69 |
|
| | | | | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
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/for the Six Months Ended June 30,
|
| 2015 | | 2014 | 2016 | | 2015 |
| (in thousands, except per share data) | (in thousands, except per share data) |
| | | | | | |
Total intrinsic value of time-based awards vested | $ | 13,061 |
| | $ | 15,840 |
| $ | 13,314 |
| | $ | 10,126 |
|
Total intrinsic value of time-based awards non-vested | 30,959 |
| | 31,996 |
| 31,506 |
| | 34,556 |
|
Market price per common share as of September 30, | 53.01 |
| | 50.29 |
| |
Market price per common share as of June 30, | | 57.61 |
| | 53.64 |
|
Weighted-average grant date fair value per share | 48.58 |
| | 56.64 |
| 57.11 |
| | 48.54 |
|
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
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 SeptemberJune 30, 20152016 was $19.2$21.7 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 2015,2016, the Compensation Committee awarded a total of 29,39824,280 market-basedrestricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 20172018 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions:
| | | Nine Months Ended September 30, | Six Months Ended June 30, |
| 2015 | | 2014 | 2016 | | 2015 |
| | | | | | |
Expected term of award | 3 years |
| | 3 years |
| 3 years |
| | 3 years |
|
Risk-free interest rate | 0.9 | % | | 0.8 | % | 1.2 | % | | 0.9 | % |
Expected volatility | 53.0 | % | | 55.2 | % | 52.3 | % | | 53.0 | % |
Weighted-average grant date fair value per share | $ | 57.35 |
| | $ | 56.87 |
| $ | 72.54 |
| | $ | 66.16 |
|
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 ninesix months ended SeptemberJune 30, 20152016:
|
| | | | | | | |
| | Shares
| | Weighted-Average Grant-Date Fair Value per Share
|
| | | | |
Non-vested at December 31, 2014
| | 83,721 |
| | $ | 52.98 |
|
Granted
| | 29,398 |
| | 57.35 |
|
Non-vested at September 30, 2015
| | 113,119 |
| | 54.12 |
|
| | | | |
|
| | | | | | | |
| | 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
| | (11,283 | ) | | 98.50 |
|
Non-vested at June 30, 2016
| | 84,546 |
| | 61.51 |
|
| | | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
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/for the Six Months Ended June 30, |
| 2015 | | 2014 | 2016 | | 2015 |
| (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 | $ | 5,996 |
| | $ | 5,746 |
| 4,871 |
| | 6,068 |
|
Market price per common share as of September 30, | 53.01 |
| | 50.29 |
| |
Market price per common share as of June 30, | | 57.61 |
| | 53.64 |
|
Weighted-average grant date fair value per share | 57.35 |
| | 56.87 |
| 72.54 |
| | 66.16 |
|
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 SeptemberJune 30, 20152016 was $2.4$2.2 million. This cost is expected to be recognized over a weighted-average period of 1.72.0 years.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 12 - EARNINGS PER SHARE
Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, Convertible Notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.
The following table presents a reconciliation of the weighted-average diluted shares outstanding:
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in thousands) |
| | | | | | | |
Weighted-average common shares outstanding - basic | 40,085 |
| | 35,834 |
| | 38,837 |
| | 35,763 |
|
Dilutive effect of: | | | | | | | |
Restricted stock | — |
| | 259 |
| | — |
| | 287 |
|
SARs | — |
| | 56 |
| | — |
| | 45 |
|
Stock options | — |
| | 1 |
| | — |
| | 1 |
|
Non-employee director deferred compensation | — |
| | 6 |
| | — |
| | 5 |
|
Convertible notes | — |
| | 672 |
| | — |
| | 730 |
|
Weighted-average common shares and equivalents outstanding - diluted | 40,085 |
| | 36,828 |
| | 38,837 |
| | 36,831 |
|
| | | | | | | |
|
| | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) |
| | | | | | | |
Weighted-average common shares outstanding - basic | 46,742 |
| | 40,035 |
| | 44,175 |
| | 38,202 |
|
Weighted-average common shares and equivalents outstanding - diluted | 46,742 |
| | 40,035 |
| | 44,175 |
| | 38,202 |
|
| | | | | | | |
We reported a net loss for the three and ninesix months ended SeptemberJune 30, 2015.2016 and 2015, respectively. As a result, our basic and diluted weighted-average common shares outstanding were the same because the effect of the common share equivalents was anti-dilutive.
The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in thousands) |
| | | | | | | | | | | | | | |
Weighted-average common share equivalents excluded from diluted earnings | | | | | | | | | | | | | | |
per share due to their anti-dilutive effect: | | | | | | | | | | | | | | |
Restricted stock | 816 |
| | 4 |
| | 836 |
| | — |
| 768 |
| | 871 |
| | 745 |
| | 832 |
|
SARs | 83 |
| | 11 |
| | 87 |
| | 30 |
| |
Stock options | 4 |
| | — |
| | 4 |
| | — |
| |
Non-employee director deferred compensation | 8 |
| | — |
| | 6 |
| | — |
| |
Convertible notes | 468 |
| | — |
| | 505 |
| | — |
| 358 |
| | 677 |
| | 478 |
| | 523 |
|
Other equity-based awards | | 103 |
| | 118 |
| | 105 |
| | 99 |
|
Total anti-dilutive common share equivalents | 1,379 |
| | 15 |
| | 1,438 |
| | 30 |
| 1,229 |
| | 1,666 |
| | 1,328 |
| | 1,454 |
|
| | | | | | | | | | | | | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
In November 2010, we issued our Convertible Notes, which givegave the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The Convertible Notes could bematured in May 2016. See Note 7, Long-Term Debt, for additional information. Prior to maturity, the Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceedsexceeded the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the three and ninesix months ended SeptemberJune 30, 2016 and 2015 as the effect would be anti-dilutive to our earnings per share. Shares issuable upon conversion of the Convertible Notes were included in the diluted earnings per share calculation for the three and nine months ended September 30, 2014, as the average market price during the period exceeded the conversion price.
NOTE 13 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS
In October 2014, we completed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million, comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million. The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million. Proceeds from the divestiture were used to reduce outstanding borrowings on our revolving credit facility and to fund a portion of our 2014 capital budget. The divestiture represented a strategic shift that will have a major effect on our operations, in that our organizational structure no longer has joint venture partners or dry gas assets. Therefore, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the condensed consolidated statements of operations for the three and nine months ended September 30, 2014.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents condensed consolidated statement of operations data related to discontinued operations:
|
| | | | | | | | |
Condensed consolidated statements of operations - discontinued operations | | Three Months Ended September 30, 2014 | | Nine Months Ended September 30, 2014
|
| | (in thousands) |
Revenues | | | | |
Crude oil, natural gas and NGLs sales | | $ | 5,411 |
| | $ | 24,149 |
|
Commodity price risk management income (loss), net | | 1,929 |
| | (1,085 | ) |
Well operations, pipeline income and other | | — |
| | 48 |
|
Total revenues | | 7,340 |
| | 23,112 |
|
| | | | |
Costs, expenses and other | | | | |
Production costs | | 1,020 |
| | 7,120 |
|
Impairment of crude oil and natural gas properties | | 273 |
| | 433 |
|
Depreciation, depletion and amortization | | 1,272 |
| | 9,128 |
|
Other | | 1,061 |
| | 3,445 |
|
Gain on sale of properties and equipment | | (1 | ) | | (193 | ) |
Total costs, expenses and other | | 3,625 |
| | 19,933 |
|
| | | | |
Interest expense | | (709 | ) | | (2,222 | ) |
Interest income | | 62 |
| | 194 |
|
Income from discontinued operations | | 3,068 |
| | 1,151 |
|
Provision for income taxes | | (3,148 | ) | | (759 | ) |
Income (loss) from discontinued operations, net of tax | | $ | (80 | ) | | $ | 392 |
|
| | | | |
The following table presents supplemental cash flows information related to our 50% ownership interest in PDCM, which is classified as discontinued operations:
|
| | | | |
Supplemental cash flows information - discontinued operations | | Nine Months Ended September 30, 2014 |
| | (in thousands) |
Cash flows from investing activities: | | |
Capital expenditures | | $ | (17,253 | ) |
| | |
Significant non-cash investing items: | | |
Change in accounts payable related to purchases of properties and equipment
| | (5,727 | ) |
Assets held for sale of $2.9 million as of September 30, 2015 and December 31, 2014 represents the carrying value of approximately 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters.
NOTE 1413 - BUSINESS SEGMENTS
We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated.
Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas and NGLs. Segment revenue includes crude oil, natural gas and NGLs sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of crude oilproperties and natural gas properties,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 us and others.unrelated third-parties. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income, less costs of natural gas marketing and direct general and administrative expense.
Unallocated Amounts. Unallocated income includes unallocated other revenue, less corporate general and administrative expense, corporate DD&A expense, interest income and interest expense. Unallocated assets include assets utilized for corporate general and administrative purposes, as well as assets not specifically included in our two business segments.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following tables present our segment information:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in thousands) |
Segment revenues: | | | | | | | | | | | | | | |
Oil and gas exploration and production | $ | 228,520 |
| | $ | 211,259 |
| | $ | 418,356 |
| | $ | 385,867 |
| $ | 18,218 |
| | $ | 48,437 |
| | $ | 106,878 |
| | $ | 189,836 |
|
Gas marketing | 2,580 |
| | 13,297 |
| | 8,336 |
| | 62,649 |
| 1,879 |
| | 2,523 |
| | 4,050 |
| | 5,756 |
|
Total revenues | $ | 231,100 |
| | $ | 224,556 |
| | $ | 426,692 |
| | $ | 448,516 |
| $ | 20,097 |
| | $ | 50,960 |
| | $ | 110,928 |
| | $ | 195,592 |
|
| | | | | | | | | | | | | | |
Segment income (loss) before income taxes: | | | | | | | | | | | | | | |
Oil and gas exploration and production | $ | (32,046 | ) | | $ | 136,886 |
| | $ | (20,309 | ) | | $ | 174,612 |
| $ | (118,508 | ) | | $ | (44,364 | ) | | $ | (152,541 | ) | | $ | 16,161 |
|
Gas marketing | (201 | ) | | (51 | ) | | (539 | ) | | 3 |
| (246 | ) | | (313 | ) | | (653 | ) | | (338 | ) |
Unallocated | (30,414 | ) | | (47,362 | ) | | (91,014 | ) | | (135,472 | ) | (35,023 | ) | | (32,309 | ) | | (113,952 | ) | | (65,024 | ) |
Income (loss) before income taxes | $ | (62,661 | ) | | $ | 89,473 |
| | $ | (111,862 | ) | | $ | 39,143 |
| |
Loss before income taxes | | $ | (153,777 | ) | | $ | (76,986 | ) | | $ | (267,146 | ) | | $ | (49,201 | ) |
| | | | | | | | | | | | | | |
|
| | | | | | | |
| September 30, 2015 | | December 31, 2014 |
| (in thousands) |
Segment assets: | | | |
Oil and gas exploration and production | $ | 2,261,164 |
| | $ | 2,254,751 |
|
Gas marketing | 4,266 |
| | 6,979 |
|
Unallocated | 76,006 |
| | 75,984 |
|
Assets held for sale | 2,874 |
| | 2,874 |
|
Total assets | $ | 2,344,310 |
| | $ | 2,340,588 |
|
| | | |
NOTE 15 - SUBSEQUENT EVENT |
| | | | | | | |
| June 30, 2016 | | December 31, 2015 |
| (in thousands) |
Segment assets: | | | |
Oil and gas exploration and production | $ | 2,244,799 |
| | $ | 2,294,288 |
|
Gas marketing | 4,117 |
| | 4,217 |
|
Unallocated | 22,754 |
| | 72,038 |
|
Total assets | $ | 2,271,670 |
| | $ | 2,370,543 |
|
| | | |
On October 26, 2015, we announced that Gysle Shellum, Chief Financial Officer, will retire effective June 30, 2016. He will remain the Chief Financial Officer until a successor is appointed and will thereafter assist with transitional and other assigned matters through his retirement date.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements.
EXECUTIVE SUMMARY
Financial Overview
Production volumes from continuing operations increased substantially to 4.35.2 MMboe and 10.69.8 MMboe for the three and ninesix months ended SeptemberJune 30, 2015,2016, respectively, representing an increaseincreases of 84%54% and 58%56%, respectively, as compared to the three and ninesix months ended SeptemberJune 30, 2014.2015. The increase in production volumes was primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field and, to a lesser extent, the completion of two four-well pads in the Utica Shale in late 2014 and early 2015.Field. Crude oil production from continuing operations increased 87%26% and 53%35% for the three and ninesix months ended SeptemberJune 30, 2015, respectively, while NGLs production from continuing operations increased 72% and 48%,2016, respectively, compared to the same prior year periods. Crude oil production comprised approximately 46%38% and 40% of total production from continuing operations during bothin the three and ninesix months ended SeptemberJune 30, 2015.2016. Our ratio of crude oil production to total production decreased as expected as we shifted our focus to the higher gas to oil ratio inner core area of the Wattenberg Field. We expect our ratio of crude oil to total production to increase during the second half of 2016 as we move drilling operations back toward the middle core area of the Wattenberg Field. Natural gas production from continuing operations increased 86%73% and 69% duringin the three and ninesix months ended SeptemberJune 30, 2015,2016, respectively, compared to the three and six months ended June 30, 2015. NGL production increased 93% and 85% for the three and six months ended June 30, 2016, respectively, compared to the same prior year periods, dueperiods. Our inner core wells have shown stronger wet gas production than anticipated, which has contributed to the growth of gas and NGL production. The majority of our recent focus on developmental drilling inwells turned-in-line during the gassier inner and middle core areasthree months ended March 31, 2016 occurred toward the end of the Wattenberg Field.quarter, while wells turned-in-line during the three months ended June 30, 2016 occurred more evenly throughout the period. As expected, this drove our quarter-over-quarter production increase of approximately 0.6 Mboe, or 14%. We expect the timing of the wells to be turned-in-line during the three months ended September 30, 2016 to be relatively even, similar to the timing for the three months ended June 30, 2016. We expect a modest increase in production for the third quarter as compared to the second quarter. For the month ended June 30, 2016, our average production rate was 58 MBoe per day, up from 42 MBoe per day for the month ended June 30, 2015.
Crude oil, natural gas and NGLs sales, from continuing operations, coupled with the impact of settlement ofsettled derivatives, increased during the three and ninesix months ended SeptemberJune 30, 2015. Increased2016 relative to the same prior year periods. Crude oil, natural gas and NGLs sales increased to $110.8 million and $186.2 million during the three and six months ended June 30, 2016 compared to $96.9 million and $171.0 million in the same prior year periods due to 54% and 56% increases in production, respectively, offset in part by 26% and 30% decreases, respectively, in the realized price per barrel of crude oil equivalent ("Boe"). The realized prices per Boe were $21.33 and $19.07 for the three and six months ended June 30, 2016, respectively, compared to $28.79 and $27.32, respectively, for the same prior year periods. Positive net settlements on derivatives increased to $53.3 million and $120.1 million during the three and six months ended June 30, 2016, respectively, compared to positive net settlements on derivative positions more than offsetderivatives of $44.1 million and $94.5 million in the effect of declines in commodity prices during the quarter. Lowersame prior year periods, due to lower crude oil and natural gas index prices duringsettlement prices. As a result of these increases, crude oil, natural gas and NGLs sales and the three and nine months ended September 30, 2015 were the primary reason for significant positiveimpact of net settlements on derivative positions of $68.0settled derivatives totaled $164.1 million and $162.5 million, respectively, compared to negative net settlements of $4.5 million and $21.5$306.3 million during the three and ninesix months ended SeptemberJune 30, 2014,2016, respectively, compared to $141.0 million and $265.5 million during the three and six months ended June 30, 2015, respectively. Crude oil, natural gasThis represents increases of 16% and NGLs sales,15% during the three and six months ended June 30, 2016, respectively, compared to the same prior year periods. The realized prices per Boe, including the impact of net settlements on derivatives, were $172.5 million$31.58 and $438.0 million during$31.36 for the three and ninesix months ended SeptemberJune 30, 2015,2016, respectively, compared to $116.0 million$41.88 and $350.1 million during the three and nine months ended September 30, 2014, respectively. This represents increases of 49% and 25%, respectively, in the three and nine months ended September 30, 2015, compared to$42.40 for the same prior year periods.periods, respectively.
SignificantAdditional significant changes impacting our results of operations for the three months ended SeptemberJune 30, 20152016 include the following:
Crude oil, natural gas and NGLs sales from continuing operations decreased to $104.5 million during the three months ended September 30, 2015 compared to $120.5 million in the same prior year period, due to a 53% decrease in the weighted-average realized prices of crude oil, natural gas and NGLs, offset in part by an 84% increase in production;
Positive net settlements on derivatives increased to $68.0 million during the three months ended September 30, 2015 compared to negative net settlements on derivatives of $4.5 million in the same prior year period, due to lower crude oil and natural gas index settlement prices;
PositiveNegative net change in the fair value of unsettled derivative positions during the three months ended SeptemberJune 30, 20152016 was $55.5$146.1 million compared to a positivenegative net change in the fair value of unsettled derivative positions of $94.7$93.1 million during the same prior year period,period. The decrease in fair value of unsettled derivative positions was primarily attributable to the downwarda more significant upward shift in the crude oil and natural gas forward curvecurves that occurred in both periods;
General and administrative expense decreasedduring the current quarter as compared to $18.5 million for the three months ended SeptemberJune 30, 2015 compared to $34.6 million in the same prior year period, primarily attributable to $16.2 million recorded during the three months ended September 30, 2014 in connection with certain partnership-related class action litigation and estimates relating to litigation arising from bankruptcy proceedings of certain affiliated partnerships;
Impairment of crude oil and natural gas properties increased to $153.5 million for the three months ended September 30, 2015 compared to $1.9 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;2015; and
Depreciation, depletion and amortization expense increased to $80.9$107.0 million during the three months ended SeptemberJune 30, 20152016 compared to $49.6$70.1 million in the same prior year period, primarily due to increased production, offset in part by lower weighted-average depreciation, depletion and amortization rates.production.
SignificantAdditional significant changes impacting our results of operations for the ninesix months ended SeptemberJune 30, 20152016 include the following:
Crude oil, natural gas and NGLs sales from continuing operations decreased to $275.5 million during the nine months ended September 30, 2015 compared to $371.6 million in the same prior year period, due to a 53% decrease in the weighted-average realized prices of crude oil, natural gas and NGLs, offset in part by a 58% increase in production;
Positive net settlements on derivatives increased to $162.5 million during the nine months ended September 30, 2015 compared to negative net settlements on derivatives of $21.5 million in the same prior year period, due to lower crude oil and natural gas index settlement prices;
Negative net change in the fair value of unsettled derivative positions during the ninesix months ended SeptemberJune 30, 20152016 was $21.3$201.8 million compared to a positivenegative net change in the fair value of unsettled derivative positions of $34.2$76.8 million during the
same prior year period,period. The decrease in fair value of unsettled derivative positions was primarily attributable to a higher beginning-of-period fair value of derivatives instruments that settled during the six months ended June 30, 2016 and an upward shift in the crude oil and natural gas derivativesforward curves that settledoccurred during the nine months ended September 30, 2015;
General and administrative expense decreased to $55.9 million for the nine months ended September 30, 2015 compared to $96.5 million in the same prior year period, primarily attributable to $40.3 million recorded during the nine months ended September 30, 2014 in connection with certain partnership-related class action litigation and estimates relating to litigation arising from bankruptcy proceedingssecond quarter of certain affiliated partnerships;
Impairment of crude oil and natural gas properties increased to $158.8 million for the nine months ended September 30, 2015 compared to $3.6 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; and2016;
Depreciation, depletion and amortization expense increased to $206.9$204.4 million during the ninesix months ended SeptemberJune 30, 20152016 compared to $142.2$125.9 million in the same prior year period, primarily due to increased production offset in part by lowerand, to a lesser extent, a higher weighted-average depreciation, depletion and amortization rates.rate; and
During the first quarter of 2016, we determined that collection of two third-party notes receivable arising from the sale of our interest in properties in the Marcellus Shale was not reasonably assured based upon current market conditions and new information
made available to a significant decline in commodity prices and a decrease in net-back realizations, we experienced a triggering event that required us to assess our crude oil and natural gas properties for possible impairment during the third quarter of 2015.us. As a result, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.7 million outstanding balance as of March 31, 2016. As of June 30, 2016, there has been no change to our assessment we recorded an impairment charge 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 current outlookcollectibility of the notes. See Note 3, Fair Value of Financial Instruments - Notes Receivable, to our condensed consolidated financial statements included elsewhere in this report for future commodity prices, 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. We had no proved undeveloped reserves in the Utica Shale in our December 31, 2014 reserve report. Therefore, we do not believe that there will be a material change in our estimated reserve quantities at December 31, 2015 as a result of these impairments.additional information.
DespiteIn 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 current commodity price environment,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, the principal amount owed upon the maturity of the Convertible Notes in May 2016 and retained the remainder for general corporate purposes.
The Convertible Notes matured in May 2016. We paid the aggregate principal amount, plus cash for fractional shares, totaling approximately $115 million, utilizing proceeds from the offering. Additionally, we haveissued 792,406 shares of common stock for the excess conversion value.
In June 2016, we entered into definitive agreements with Noble Energy, Inc. and certain of its subsidiaries ("Noble") to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the terms of the agreements, this strategic trade includes leasehold acreage only, and does not materially altered the company-wide development plan utilizedinclude production or wellbores. We expect to receive approximately 13,500 net acres in our December 31, 2014 reserve reportexchange for approximately 11,700 net acres, subject, in each case, to title examination and other customary adjustments. The difference in net acres is primarily due to drilling efficiencies and a reductionvariances in our well development costs. See our 2014 Form 10-Knet revenue interests. This acreage trade is expected to increase opportunities for a sensitivity analysis on how changes in commodity prices would have impacted our estimated reserves quantities at December 31, 2014. Due to these factors, we believe the projected SEC commodity prices to be usedlonger horizontal laterals with significantly increased working interests, while minimizing potential surface impact. We anticipate closing this transaction early in the 2015 year-end reserve report will not cause a material reduction in the quantityfourth quarter of our estimated proved reserves. However, we expect these factors will cause the pre-tax present value using the projected SEC commodity prices for future net revenues (“PV-10”) to significantly decrease at December 31, 2015. The actual impact on December 31, 2015 SEC reserve quantities and their PV-10 value will depend upon the facts and circumstances at year-end.2016.
Available liquidity as of SeptemberJune 30, 20152016 was $392.0$547.4 million compared to $398.4$402.2 million as of December 31, 2014.2015. Available liquidity as of SeptemberJune 30, 20152016 is comprised of $3.7$109.1 million of cash and cash equivalents and $388.3$438.3 million available for borrowing under our revolving credit facility. These amounts exclude an additional $250 million available under our revolving credit facility, subject to certain terms and conditions of the agreement. In September 2015,May 2016, we completed the semi-annual redetermination of the borrowing base under 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.
In March 2015, we completed a public offering of 4,002,000 shares of our common stock for net proceeds of approximately $203 million, after deducting offering expenses and underwriting discounts. We used a portion of the proceeds of the offering to repay all amounts then outstanding on our revolving credit facility, and used the remaining amounts to fund a portion of our capital program. With our current derivative position, available liquidity and expected cash flows from operations, we believe we have sufficient liquidity to allow us to fund our operations and execute our expected capital program through the remainder of 2015.2016 development program.
Operational Overview
Drilling Activities.Activities. During the ninesix months ended SeptemberJune 30, 2015,2016, we continued to execute our strategic plan of increasingto grow production reserveswhile preserving our financial strength and liquidity by managing our capital spending to approximate our cash flows from operations. Through July 2016, we ran four automated drilling operationsrigs in the Wattenberg Field in Colorado and completion activities in the Utica Shale play in southeastern Ohio. In the Wattenberg Field, we are currently running five automated drilling rigs and expect to decrease our rig count to four in the fourth quarter of 2015 due to the increases in our drilling rig efficiencies.Field. During the ninesix months ended SeptemberJune 30, 2015,2016, we spud 13076 horizontal wells and turned-in-line 9381 horizontal wells in the Wattenberg Field. We also participated in 3824 gross, 4.76.5 net, horizontal non-operated wells that were spud and 2412 gross, 5.43.2 net, horizontal non-operated wells which were turned-in-line. We began implementing several well-recovery enhancementsDuring the six months ended June 30, 2016, we drilled and completed five wells in 2015, including tighter spacing between frac intervals on all wells and drilling 40% of our wells with extended reach laterals of 6,500 feet to 7,000 feet. We have been able to improve our drilling time due to several factors, including the use of automated drilling rigs that minimize downtime, improved drilling team cohesion and utilizing analytics to improve drilling efficiencies. In the Utica Shale, we completed andthree of which were turned-in-line a four-well pad during the first half of 2015. Asperiod. Of these three wells, one is a result of10,000 foot lateral well located in Guernsey County and two are 6,000 foot lateral wells located in Washington County. We plan to turn-in-line the four-well pads turned-in-line attwo remaining wells over the end of 2014 and the second quarter of 2015, production volumes from the Utica Shale increased 57% and 48% during the three and nine months ended September 30, 2015, respectively, compared to the same prior year periods.next several months.
20152016 Operational Outlook
We expect to meet or slightly exceedare raising the high endmid-point of our prior 2015 production guidance range and now expect our production for 2016 to be between 21.0 MMBoe and 22.0 MMBoe and that our production rate will average approximately 58,000 to 60,000 Boe per day. Our revised 2016 capital forecast of 15.0 MMBoe, while maintaining our previously provided capital guidance range of $520$400 million to $550 million. Through$420 million is focused on continuing to provide value-driven production growth by exploiting our substantial inventory of reasonable rate-of-return projects in the nineWattenberg Field.
Wattenberg Field. As a result of increased working interests in planned wells resulting from the anticipated acreage exchange with Noble, we reduced the number of rigs in the Wattenberg Field drilling plan to three beginning in August 2016. With the reduction from four drilling rigs to three in the Wattenberg Field, our 2016 capital forecast has been slightly reduced to approximately $375 million in the field, comprised of approximately $340 million for our operated drilling program and approximately $20 million for non-operated projects. The remainder of the Wattenberg Field capital is expected to be used for leasing, workover projects and other capital improvements. We plan to spud 128 and turn-in-line 140 horizontal Niobrara or Codell wells and participate in approximately 15 gross, 4.0 net, non-operated horizontal opportunities in 2016. During the six months ended SeptemberJune 30, 2015,2016, we invested approximately $182 million, or approximately 49%, of our 2016 capital forecast for the Wattenberg Field.
Utica Shale. As of June 30, 2016, all of our drilling and completion activity in the Utica Shale for 2016 has been completed as described above. We plan to turn-in-line the two remaining wells during the second half of 2016 once midstream pipeline facilities are available for connection. Additionally, we plan to perform modest amounts of drill site preparation and to pursue infill leasing opportunities. During the six months ended June 30, 2016, we have invested approximately $421$25 million or 77% to 81%, of our total 2016 capital forecast. Crude oil is expected to comprise 47%forecast for the Utica Shale of our revised production and we expect a year-end exit rate exceeding 48,000 Boe per day. We expect to direct the remaining capital primarily to our drilling program in the Wattenberg Field, where we have reduced our per well development costs for both standard and extended reach laterals. Further, due toapproximately $30 million.
improved
2016 Operational Flexibility
In December 2015, the Board of Directors approved our 2016 development plan. This plan, which primarily focuses on the drilling techniques and reduced drilling time,program in the number of horizontal Niobrara or Codell horizontal wells expectedWattenberg Field, was based upon our goal to be spud and turned-in-line in 2015 is approximately 176 and 137, respectively. During the third quarter of 2015,preserve our balance sheet by managing our capital spending to approximate our cash flows from operations approximatedoperations. Additionally, with the proceeds from our March 2016 equity offering and settlement of our convertible notes in May 2016, we believe we have further strengthened our balance sheet, while concurrently increasing production and cash flowsflows.
We maintain significant operational flexibility to reduce the pace of our capital spending. We will continue to monitor future commodity prices, and should prices remain depressed or further deteriorate, we believe an adjustment to our development plan may be appropriate. We believe we have ample opportunities to reduce capital spending, including but not limited to: working with our vendors to achieve further cost reductions; reducing the number of rigs being utilized in our drilling program; and/or managing our completion schedule. The production impact of reduced 2016 capital spending would be felt primarily in 2017 and thereafter, as our anticipated long-term production growth would likely be reduced. This operational flexibility is maintained with little exposure to incurring additional costs, given that all of our acreage in the Wattenberg Field is held by production, a reduction in rigs would not cause us to incur substantial idling costs as our rig commitments are short term (30 to 90 days), and we do not anticipate having additional material unfulfilled transportation commitment fees.
Ballot Initiative Update
Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state. Proponents of two such initiatives have submitted signatures in an effort to qualify the initiatives to appear on the ballot in November 2016. The signatures are subject to a verification process to be conducted by the Colorado Secretary of State. This process could take up to 30 days. We do not know what the outcome of this process will be. However, based on unofficial reports regarding the number of signatures submitted and the expectation that some signatures will be invalidated, we believe there is a substantial likelihood that the initiatives will not qualify for the ballot. If the initiatives qualify and are approved by the voters of Colorado, the proposals will take effect by the end of 2016.
One of the initiatives that could appear on the ballot, which we refer to as the “local control” initiative, would amend 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. The other initiative, which we refer to as the “setback” initiative, would amend the state constitution to require all new oil and gas development facilities to be located at least 2,500 feet away from investingany occupied structure or “area of special concern,” broadly defined to include 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. The current minimum required setback between oil and gas wells and occupied structures is generally 500 feet. If implemented, the 2,500 foot setback proposal would effectively prohibit the vast majority of our planned future drilling activities and would therefore make it impossible to pursue our current development plans. The local control proposal would potentially have a similar effect, depending on the nature and extent of regulations implemented by relevant local governmental authorities.
Because substantially all of our current operations and reserves are located in Colorado, the risks we expectface with respect to these proposals, and possible similar future proposals, are greater than those of our competitors with more geographically diverse operations. We cannot predict the same foroutcome of the remainder of 2015.potentially pending initiatives or possible future regulatory developments.
Wattenberg FieldSee Part II, Item1A, . We expect to spud approximately 176 and turn-in-line 133 horizontal Niobrara or Codell wells in 2015, of which approximately 40% are expected to be extended reach laterals of approximately 6,500 feet to 7,000 feet. DuringRisk Factors, for additional information regarding the three months ended September 30, 2015, we spud 53 horizontal wells and turned-in-line 33 operated horizontal wells. Approximately 75% of the wells are expected to target the Niobrara formation, with the remainder targeting the Codell formation. We expect to participate in approximately 54 gross, 8.5 net, non-operated horizontal opportunities in 2015. During the nine months ended September 30, 2015, we invested approximately $395 million in the Wattenberg Field.ballot initiatives.
Utica Shale. Based upon current low commodity prices and large natural gas price differentials in Appalachia, we elected to temporarily cease drilling in the Utica Shale in early 2015 in favor of allocating more of our 2015 capital program to our higher return projects in the Wattenberg Field's inner and middle core areas. In 2015, we directed our investment in the Utica Shale to complete and turn-in-line the four-well pad that was in-process as of December 31, 2014 and for lease maintenance, exploration and other expenditures. During the nine months ended September 30, 2015, we invested approximately $23 million in the Utica Shale, the majority of which was for completion activities on the four-well pad. In the fourth quarter of 2015, we expect to make a moderate capital investment in our Washington County acreage so as to provide further support for future drilling on our southern acreage in the Utica Shale.
Results of Operations
Summary Operating Results
The following table presents selected information regarding our operating results from continuing operations:results:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| 2015 | | 2014 | | Percentage Change | | 2015 | | 2014 | | Percentage Change | 2016 | | 2015 | | Percentage Change | | 2016 | | 2015 | | Percentage Change |
| (dollars in millions, except per unit data) | (dollars in millions, except per unit data) |
Production (1) | | | | | | | | | | | | | | | | | | | | | | |
Crude oil (MBbls) | 2,007.8 |
| | 1,072.3 |
| | 87.2 | % | | 4,895.9 |
| | 3,192.3 |
| | 53.4 | % | 1,992.6 |
| | 1,581.4 |
| | 26.0 | % | | 3,900.4 |
| | 2,888.1 |
| | 35.1 | % |
Natural gas (MMcf) | 9,148.9 |
| | 4,910.1 |
| | 86.3 | % | | 22,997.0 |
| | 13,611.1 |
| | 69.0 | % | 12,672.8 |
| | 7,323.7 |
| | 73.0 | % | | 23,350.8 |
| | 13,848.1 |
| | 68.6 | % |
NGLs (MBbls) | 793.0 |
| | 461.7 |
| | 71.8 | % | | 1,858.5 |
| | 1,252.2 |
| | 48.4 | % | 1,092.5 |
| | 565.0 |
| | 93.4 | % | | 1,974.7 |
| | 1,065.5 |
| | 85.3 | % |
Crude oil equivalent (MBoe) (2) | 4,325.6 |
| | 2,352.3 |
| | 83.9 | % | | 10,587.3 |
| | 6,713.0 |
| | 57.7 | % | 5,197.1 |
| | 3,367.1 |
| | 54.3 | % | | 9,766.8 |
| | 6,261.7 |
| | 56.0 | % |
Average MBoe per day | 47.0 |
| | 25.6 |
| | 83.9 | % | | 38.8 |
| | 24.6 |
| | 57.7 | % | 57.1 |
| | 37.0 |
| | 54.3 | % | | 53.7 |
| | 34.6 |
| | 56.0 | % |
Crude Oil, Natural Gas and NGLs Sales | | | | | | | | | | | | | | | | | | | | | | |
Crude oil | $ | 78.3 |
| | $ | 90.8 |
| | (13.8 | )% | | $ | 206.7 |
| | $ | 279.4 |
| | (26.0 | )% | $ | 80.4 |
| | $ | 76.4 |
| | 5.2 | % | | $ | 134.4 |
| | $ | 128.4 |
| | 4.7 | % |
Natural gas | 18.8 |
| | 17.2 |
| | 9.3 | % | | 49.4 |
| | 55.0 |
| | (10.2 | )% | 17.4 |
| | 14.9 |
| | 16.8 | % | | 32.3 |
| | 30.6 |
| | 5.6 | % |
NGLs | 7.4 |
| | 12.5 |
| | (40.8 | )% | | 19.4 |
| | 37.2 |
| | (47.8 | )% | 13.0 |
| | 5.6 |
| | 132.1 | % | | 19.5 |
| | 12.0 |
| | 62.5 | % |
Total crude oil, natural gas and NGLs sales | $ | 104.5 |
| | $ | 120.5 |
| | (13.3 | )% | | $ | 275.5 |
| | $ | 371.6 |
| | (25.9 | )% | $ | 110.8 |
| | $ | 96.9 |
| | 14.3 | % | | $ | 186.2 |
| | $ | 171.0 |
| | 8.9 | % |
| | | | | | | | | | | | | | | | | | | | | | |
Net Settlements on Derivatives (3) | | | | | | | | | | | | | | | | | | | | | | |
Crude oil | | $ | 38.7 |
| | $ | 37.0 |
| | 4.6 | % | | $ | 92.0 |
| | $ | 81.7 |
| | 12.6 | % |
Natural gas | $ | 7.3 |
| | $ | 0.3 |
| | * |
| | $ | 20.1 |
| | $ | (3.9 | ) | | * |
| 14.6 |
| | 7.1 |
| | 105.6 | % | | 28.1 |
| | 12.8 |
| | 119.5 | % |
Crude oil | 60.7 |
| | (4.8 | ) | | * |
| | 142.4 |
| | (17.6 | ) | | * |
| |
Total net settlements on derivatives | $ | 68.0 |
| | $ | (4.5 | ) | | * |
| | $ | 162.5 |
| | $ | (21.5 | ) | | * |
| $ | 53.3 |
| | $ | 44.1 |
| | 20.9 | % | | $ | 120.1 |
| | $ | 94.5 |
| | 27.1 | % |
| | | | | | | | | | | | | | | | | | | | | | |
Average Sales Price (excluding net settlements on derivatives) | | | | | | | | | | | | | | | | | | | | | | |
Crude oil (per Bbl) | $ | 38.98 |
| | $ | 84.67 |
| | (54.0 | )% | | $ | 42.22 |
| | $ | 87.51 |
| | (51.8 | )% | $ | 40.37 |
| | $ | 48.31 |
| | (16.4 | )% | | $ | 34.46 |
| | $ | 44.47 |
| | (22.5 | )% |
Natural gas (per Mcf) | 2.05 |
| | 3.50 |
| | (41.4 | )% | | 2.15 |
| | 4.04 |
| | (46.8 | )% | 1.37 |
| | 2.03 |
| | (32.5 | )% | | 1.38 |
| | 2.21 |
| | (37.6 | )% |
NGLs (per Bbl) | 9.40 |
| | 27.15 |
| | (65.4 | )% | | 10.45 |
| | 29.73 |
| | (64.9 | )% | 11.93 |
| | 10.01 |
| | 19.2 | % | | 9.89 |
| | 11.23 |
| | (11.9 | )% |
Crude oil equivalent (per Boe) | 24.15 |
| | 51.24 |
| | (52.9 | )% | | 26.02 |
| | 55.35 |
| | (53.0 | )% | 21.33 |
| | 28.79 |
| | (25.9 | )% | | 19.07 |
| | 27.32 |
| | (30.2 | )% |
| | | | | | | | | | | | | | | | | | | | | | |
Average Lease Operating Expenses (per Boe) (4) | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | $ | 3.00 |
| | $ | 4.73 |
| | (36.6 | )% | | $ | 4.06 |
| | $ | 4.67 |
| | (13.1 | )% | $ | 2.66 |
| | $ | 3.92 |
| | (32.1 | )% | | $ | 3.00 |
| | $ | 4.80 |
| | (37.5 | )% |
Utica Shale | 1.17 |
| | 2.68 |
| | (56.3 | )% | | 1.49 |
| | 1.79 |
| | (16.8 | )% | 2.08 |
| | 1.55 |
| | 34.2 | % | | 2.28 |
| | 1.67 |
| | 36.5 | % |
Weighted-average | 2.87 |
| | 4.56 |
| | (37.1 | )% | | 3.85 |
| | 4.42 |
| | (12.9 | )% | 2.63 |
| | 3.71 |
| | (29.1 | )% | | 2.97 |
| | 4.52 |
| | (34.3 | )% |
| | | | | | | | | | | | | | | | | | | | | | |
Natural Gas Marketing Contribution Margin (5) | $ | (0.2 | ) | | $ | — |
| | * |
| | $ | (0.6 | ) | | $ | — |
| | * |
| $ | (0.2 | ) | | $ | (0.3 | ) | | (33.3 | )% | | $ | (0.6 | ) | | $ | (0.3 | ) | | (100.0 | )% |
| | | | | | | | | | | | | | | | | | | | | | |
Other Costs and Expenses | | | | | | | | | | | | | | | | | | | | | | |
Exploration expense | $ | 0.3 |
| | $ | 0.2 |
| | 32.6 | % | | $ | 0.8 |
| | $ | 0.8 |
| | 5.0 | % | |
Impairment of crude oil and natural gas properties | 153.5 |
| | 1.9 |
| | * |
| | 158.8 |
| | 3.6 |
| | * |
| |
Production taxes | | $ | 6.0 |
| | $ | 3.8 |
| | 57.5 | % | | $ | 10.1 |
| | $ | 7.7 |
| | 30.8 | % |
Transportation, gathering and processing expenses | | 4.5 |
| | 1.3 |
| | 241.4 | % | | 8.5 |
| | 2.6 |
| | 221.5 | % |
Impairment of properties and equipment | | 4.2 |
| | 4.4 |
| | (5.3 | )% | | 5.2 |
| | 7.2 |
| | (27.9 | )% |
General and administrative expense | 18.5 |
| | 34.6 |
| | (46.5 | )% | | 55.9 |
| | 96.5 |
| | (42.1 | )% | 23.6 |
| | 20.7 |
| | 13.8 | % | | 46.4 |
| | 41.8 |
| | 11.0 | % |
Depreciation, depletion and amortization | 80.9 |
| | 49.6 |
| | 63.1 | % | | 206.9 |
| | 142.2 |
| | 45.5 | % | 107.0 |
| | 70.1 |
| | 52.6 | % | | 204.4 |
| | 125.9 |
| | 62.3 | % |
Provision for uncollectible notes receivable | | — |
| | — |
| | * |
| | 44.7 |
| | — |
| | * |
|
| | | | | | | | | | | | | | | | | | | | | | |
Interest expense | $ | 12.1 |
| | $ | 11.8 |
| | 2.3 | % | | $ | 35.4 |
| | $ | 36.2 |
| | (2.3 | )% | $ | 10.7 |
| | $ | 11.6 |
| | (7.7 | )% | | $ | 22.6 |
| | $ | 23.3 |
| | (3.1 | )% |
| |
* | Percentage change is not meaningful or equal to or greater than 300%. |
Amounts may not recalculate due to rounding.
______________
| |
(1) | Production is net and determined by multiplying the gross production volume of properties in which we have an interest by our ownership percentage. |
| |
(2) | One Bbl of crude oil or NGL equals six Mcf of natural gas. |
| |
(3) | Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to natural gas marketing. |
| |
(4) | Represents lease operating expenses, exclusive of production taxes, on a per unit basis. |
| |
(5) | Represents sales from natural gas marketing, net of costs of natural gas marketing, including net settlements and net change in fair value of unsettled derivatives related to natural gas marketing activities. |
Crude Oil, Natural Gas and NGLs Sales
The following tables present crude oil, natural gas and NGLs production and weighted-average sales price from continuing operations:price:
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
Production by Operating Region | | 2015 | | 2014 | | Percentage Change | | 2015 | | 2014 | | Percentage Change | | 2016 | | 2015 | | Percentage Change | | 2016 | | 2015 | | Percentage Change |
Crude oil (MBbls) | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | 1,868.6 |
| | 1,012.0 |
| | 84.6 | % | | 4,509.5 |
| | 2,973.1 |
| | 51.7 | % | | 1,894.0 |
| | 1,449.7 |
| | 30.6 | % | | 3,712.2 |
| | 2,640.9 |
| | 40.6 | % |
Utica Shale | | 139.2 |
| | 60.3 |
| | 130.8 | % | | 386.4 |
| | 219.2 |
| | 76.3 | % | | 98.6 |
| | 131.7 |
| | (25.1 | )% | | 188.2 |
| | 247.2 |
| | (23.9 | )% |
Total | | 2,007.8 |
| | 1,072.3 |
| | 87.2 | % | | 4,895.9 |
| | 3,192.3 |
| | 53.4 | % | | 1,992.6 |
| | 1,581.4 |
| | 26.0 | % | | 3,900.4 |
| | 2,888.1 |
| | 35.1 | % |
Natural gas (MMcf) | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | 8,478.3 |
| | 4,318.6 |
| | 96.3 | % | | 21,040.7 |
| | 11,971.8 |
| | 75.8 | % | | 12,097.8 |
| | 6,651.1 |
| | 81.9 | % | | 22,268.2 |
| | 12,562.4 |
| | 77.3 | % |
Utica Shale | | 670.6 |
| | 591.5 |
| | 13.4 | % | | 1,956.3 |
| | 1,639.3 |
| | 19.3 | % | | 575.0 |
| | 672.6 |
| | (14.5 | )% | | 1,082.6 |
| | 1,285.7 |
| | (15.8 | )% |
Total | | 9,148.9 |
| | 4,910.1 |
| | 86.3 | % | | 22,997.0 |
| | 13,611.1 |
| | 69.0 | % | | 12,672.8 |
| | 7,323.7 |
| | 73.0 | % | | 23,350.8 |
| | 13,848.1 |
| | 68.6 | % |
NGLs (MBbls) | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | 730.6 |
| | 421.1 |
| | 73.5 | % | | 1,692.5 |
| | 1,151.3 |
| | 47.0 | % | | 1,047.3 |
| | 509.9 |
| | 105.4 | % | | 1,887.4 |
| | 961.8 |
| | 96.2 | % |
Utica Shale | | 62.4 |
| | 40.6 |
| | 53.7 | % | | 166.0 |
| | 100.9 |
| | 64.5 | % | | 45.2 |
| | 55.1 |
| | (18.0 | )% | | 87.3 |
| | 103.7 |
| | (15.8 | )% |
Total | | 793.0 |
| | 461.7 |
| | 71.8 | % | | 1,858.5 |
| | 1,252.2 |
| | 48.4 | % | | 1,092.5 |
| | 565.0 |
| | 93.4 | % | | 1,974.7 |
| | 1,065.5 |
| | 85.3 | % |
Crude oil equivalent (MBoe) | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | 4,012.3 |
| | 2,152.9 |
| | 86.4 | % | | 9,708.8 |
| | 6,119.7 |
| | 58.6 | % | | 4,957.5 |
| | 3,068.2 |
| | 61.6 | % | | 9,310.9 |
| | 5,696.5 |
| | 63.4 | % |
Utica Shale | | 313.3 |
| | 199.4 |
| | 57.1 | % | | 878.5 |
| | 593.3 |
| | 48.1 | % | | 239.6 |
| | 298.9 |
| | (19.8 | )% | | 455.9 |
| | 565.2 |
| | (19.3 | )% |
Total | | 4,325.6 |
| | 2,352.3 |
| | 83.9 | % | | 10,587.3 |
| | 6,713.0 |
| | 57.7 | % | | 5,197.1 |
| | 3,367.1 |
| | 54.3 | % | | 9,766.8 |
| | 6,261.7 |
| | 56.0 | % |
Amounts may not recalculate due to rounding.
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
Average Sales Price by Operating Region | | | | | | Percentage Change | | | | | | Percentage Change | | | | | | Percentage Change | | | | | | Percentage Change |
(excluding net settlements on derivatives) | | 2015 | | 2014 | | 2015 | | 2014 | | | 2016 | | 2015 | | 2016 | | 2015 | |
Crude oil (per Bbl) | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | $ | 38.90 |
| | $ | 84.56 |
| | (54.0 | )% | | $ | 42.13 |
| | $ | 87.41 |
| | (51.8 | )% | | $ | 40.41 |
| | $ | 48.09 |
| | (16.0 | )% | | $ | 34.51 |
| | $ | 44.41 |
| | (22.3 | )% |
Utica Shale | | 40.02 |
| | 86.56 |
| | (53.8 | )% | | 43.28 |
| | 88.87 |
| | (51.3 | )% | | 39.57 |
| | 50.78 |
| | (22.1 | )% | | 33.44 |
| | 45.12 |
| | (25.9 | )% |
Weighted-average price | | 38.98 |
| | 84.67 |
| | (54.0 | )% | | 42.22 |
| | 87.51 |
| | (51.8 | )% | | 40.37 |
| | 48.31 |
| | (16.4 | )% | | 34.46 |
| | 44.47 |
| | (22.5 | )% |
Natural gas (per Mcf) | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | $ | 2.11 |
| | $ | 3.65 |
| | (42.2 | )% | | $ | 2.17 |
| | $ | 4.10 |
| | (47.1 | )% | | $ | 1.36 |
| | $ | 2.03 |
| | (33.0 | )% | | $ | 1.38 |
| | $ | 2.21 |
| | (37.6 | )% |
Utica Shale | | 1.36 |
| | 2.45 |
| | (44.5 | )% | | 1.92 |
| | 3.60 |
| | (46.7 | )% | | 1.58 |
| | 2.06 |
| | (23.3 | )% | | 1.51 |
| | 2.22 |
| | (32.0 | )% |
Weighted-average price | | 2.05 |
| | 3.50 |
| | (41.4 | )% | | 2.15 |
| | 4.04 |
| | (46.8 | )% | | 1.37 |
| | 2.03 |
| | (32.5 | )% | | 1.38 |
| | 2.21 |
| | (37.6 | )% |
NGLs (per Bbl) | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | $ | 9.62 |
| | $ | 25.89 |
| | (62.8 | )% | | $ | 10.36 |
| | $ | 28.17 |
| | (63.2 | )% | | $ | 11.87 |
| | $ | 10.01 |
| | 18.6 | % | | $ | 9.78 |
| | $ | 10.91 |
| | (10.4 | )% |
Utica Shale | | 6.80 |
| | 40.13 |
| | (83.1 | )% | | 11.40 |
| | 47.58 |
| | (76.0 | )% | | 13.27 |
| | 9.95 |
| | 33.4 | % | | 12.29 |
| | 14.17 |
| | (13.3 | )% |
Weighted-average price | | 9.40 |
| | 27.15 |
| | (65.4 | )% | | 10.45 |
| | 29.73 |
| | (64.9 | )% | | 11.93 |
| | 10.01 |
| | 19.2 | % | | 9.89 |
| | 11.23 |
| | (11.9 | )% |
Crude oil equivalent (per Boe) | | | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | $ | 24.32 |
| | $ | 52.13 |
| | (53.3 | )% | | $ | 26.07 |
| | $ | 55.78 |
| | (53.3 | )% | | $ | 21.27 |
| | $ | 28.78 |
| | (26.1 | )% | | $ | 19.03 |
| | $ | 27.31 |
| | (30.3 | )% |
Utica Shale | | 22.04 |
| | 41.58 |
| | (47.0 | )% | | 25.47 |
| | 51.17 |
| | (50.2 | )% | | 22.59 |
| | 28.86 |
| | (21.7 | )% | | 19.75 |
| | 27.38 |
| | (27.9 | )% |
Weighted-average price | | 24.15 |
| | 51.24 |
| | (52.9 | )% | | 26.02 |
| | 55.35 |
| | (53.0 | )% | | 21.33 |
| | 28.79 |
| | (25.9 | )% | | 19.07 |
| | 27.32 |
| | (30.2 | )% |
Amounts may not recalculate due to rounding.
For the three and ninesix months ended SeptemberJune 30, 2015,2016, crude oil, natural gas and NGLs sales revenue decreasedincreased compared to the three and ninesix months ended SeptemberJune 30, 20142015 due to the following (in millions):following:
| | | September 30, 2015 | June 30, 2016 |
| Three Months Ended | | Nine Months Ended | Three Months Ended | | Six Months Ended |
| | (in millions) |
Increase in production | | $ | 36.0 |
| | $ | 76.2 |
|
Decrease in average crude oil price | $ | (91.7 | ) | | (221.8 | ) | (15.8 | ) | | (39.0 | ) |
Decrease in average natural gas price | (13.3 | ) | | (43.5 | ) | (8.4 | ) | | (19.4 | ) |
Decrease in average NGLs price | (14.1 | ) | | (35.8 | ) | |
Increase in production | 103.1 |
| | 205.0 |
| |
Total decrease in crude oil, natural gas and NGLs sales revenue | $ | (16.0 | ) | | $ | (96.1 | ) | |
Increase (decrease) in average NGLs price | | 2.1 |
| | (2.6 | ) |
Total increase in crude oil, natural gas and NGLs sales revenue | | $ | 13.9 |
| | $ | 15.2 |
|
Production from continuing operations for the thirdsecond quarter of 20152016 was 4.35.2 million Boe, up from 2.43.4 million Boe in the thirdsecond quarter of 2014.2015. Year-to-date, production from continuing operations was 10.69.8 million Boe, up from 6.76.3 million Boe in the first ninesix months of 2014.2015. Production increased as a result of continued drilling and completion activities as discussed in Operational Overview.Overview. Gathering system line pressures decreased following the commissioning of DCP’s Lucerne II plant in the summer of 2015, down to levels that were consistent with our projections. We continued to experience high24% lower line pressures in the second quarter of 2016 as compared to the comparable period of 2015 on our primary service provider’s system. Line pressures averaged 225 pounds per square inch gage ("psig") during the second quarter of 2015 and averaged 170 psig during the second quarter of 2016. Line pressures began to build during the quarter as system volumes increased and the region experienced warmer weather. Other contributing factors to the increase in line pressures were our primary service provider experiencing significant unexpected downtime during the quarter on some of its major plants, as well as performing extensive scheduled maintenance on one of its higher capacity gas plants. As a result of the increased line pressures, we experienced a curtailment of our legacy vertical well gas production of approximately 1.2 MMcf per day, or 6% of our vertical production, at the end of June, representing approximately 0.5% of our total Wattenberg Field gas production, along with associated oil production. The 170 psig average line pressure experienced during the quarter had negligible impact on our horizontal production. We expect the gathering system pressures on the midstreamprimary service provider’s system into stabilize and then decrease as cooler weather arrives by the Wattenberg Field in the first halfend of the year, but the Lucerne II processing plant and additional new compressor stations on the gathering system began initial operations in June 2015, resulting in immediate reductions in line pressures. We have experienced further line pressure reductions in the third quarter of 2015. Further, we expect sustained relief of gathering system pressure on our primary gatherer's system through 2016, depending upon the impact of reduced drilling activity in the field going forward. However, due to continued low commodity prices, our2016.
Our secondary midstream service provider, which currently gathers and processes approximately 30%36% of our Wattenberg Field gas, has indicated it may have limitations onlimited its capital program in 2016, which may resulthas resulted in a curtailment of approximately 10 MMcf per day of our 2016 volumes. To help mitigate the impact of this curtailment, we have elected to contribute upfront capital of $0.6 million to our secondary midstream service provider to facilitate timely connection of certain of our projected 2016 volumes.well pads. We expect to be reimbursed by our secondary midstream service provider for this amount during the fourth quarter of 2016. With continued pressure on commodity prices impacting their revenue, we have seen more requests for upfront capital contributions by our third-party midstream service providers in order to ensure well connections are completed in a timely manner. We expect this trend to continue, and we will evaluate these requests on an individual basis. We rely on our third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with our production growth. As a result, the timing and availability of additional facilities going forward is beyond our control. Falling commodity prices have resulted in reduced investment in midstream facilities by some third parties, increasing the risk that sufficient midstream infrastructure will not be available in future periods.
Crude Oil, Natural Gas and NGLs Pricing. 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 NGLsNGL prices are among the most volatile of all commodity prices. TheWhile the price of crude oil decreased during the third quarterfirst half of 20152016 compared to the first half of 2015, amid continuing concerns regarding highprices increased substantially during the second quarter of 2016 as compared to the first quarter of 2016 as the number of U.S. crude oil rigs and inventories and slowing global demand for crude oil.declined. Natural gas prices decreased during the thirdfirst half of 2016 when compared to the same prior year period. Although we did experience improved pricing by the end of the second quarter of 2015 remained at2016, due to an oversupply of nearly all domestic NGLs products, our average realized sales price for NGLs during the first half of 2016 reflected the same low levels seen throughout 2015,during the last quarter of 2015. With the initiation of ethane exports and were at significantly lower levels than the comparable periods of 2014.increased demand for NGLs, we are starting to see NGL prices declined significantly during the first nine months of 2015 and, while they have stabilized with the prospect of cooler weather and crop drying season, also remain at low levels relative to those experienced in the comparable periods of 2014.trend upward.
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 primarily with monthly and longer term pricing provisions based on NYMEX pricing, adjusted for differentials. We are currently pursuinghave 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.pricing and limiting our use of trucking of production. We began delivering crude oil in accordance with our long term commitment to the White Cliffs Pipeline, LLC ("White Cliffs") pipeline at the beginning ofin July 2015. This facilitatesis one of several agreements we have entered into to facilitate deliveries of a significant portion of our crude oil to the Cushing, Oklahoma market. In addition, we have signed a long-term agreement for gathering of crude oil at the wellhead by pipeline from several of our pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability and reducing the overall physical footprint of our well pads. We expect to deliverbegan delivering crude oil into this pipeline during the fourth quarter of 2015. We continue to evaluate crude oil takeaway options to determine2015 and the benefits of additional longer term commitments to deliver to competitive markets and, as a result, have entered into some three-month and six-month agreements that have resulted in significantly improved deductions compared to earliersystem was fully operational on certain wells in the year.first half of 2016. In the Utica Shale, crude oil and condensate is sold to a local purchaserpurchasers at each individual well sitepad based on NYMEX pricing, adjusted for quality differentials.differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities or barge loading terminals on the Ohio River.
Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The price we receive for our natural gas produced in the Wattenberg Field is based on CIG and local utility prices, adjusted for certain deductions, while natural gas produced in the Utica Shale is based on TETCO M-2 pricing with a portion of our volumes currently receiving an increase in price relative to the index based upon delivery to the Chicago/Midwest market. Our sale of a significant portion of our Utica Shale gas to the Midwest market has helped to reduce the impact of the significant differentials that exist between the TETCO M-2 realizations and the NYMEX gas price.pricing. We anticipate that the significant Appalachian pipeline differentials that impact our Utica Shale natural gas will continue at least intothrough 2016.
Our price for NGLs produced in the Wattenberg Field is based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. The NGLs produced in the Utica Shale are sold based on month-to-month pricing to various markets. Due to an oversupply and growing inventoriesWhile NGL prices had been declining, we have seen a stabilization of nearly all domestic NGLs products, our realized sales price for NGLs declined significantly duringprices in the first three quarterssecond quarter of 2015 and, while these2016. We expect NGL prices have stabilized, we expect pricing to remain at depressed levels well into 2016 and perhaps beyond.stable amid indications that prices could increase later in 2016.
Our crude oil, natural gas and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the transportation method used.related purchase agreement. We use the "net-back" method of accounting for natural gas and NGLs, as well as a portionthe majority of our crude oil production, from the Wattenberg Field and for crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation, gathering and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on
the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. We use the "gross" method of accounting for Wattenberg Field crude oil delivered through the White Cliffs pipelineand Saddle Butte pipelines and for natural gas and NGLs sales related to production from the Utica Shale as the purchasers do not provide transportation, gathering or processing services. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses as a component of production costs.expenses. As a result of the White Cliffs agreement,and Saddle Butte agreements, during the threesix months ended SeptemberJune 30, 2015,2016, our Wattenberg Field crude oil average sales price increased approximately $1.28$1.65 per barrel attributable to recognizing thesebecause we recognized the costs for transportation on the White Cliffs pipelineand Saddle Butte pipelines as an increase in transportation expense, rather than as a deduction from revenues.
Production CostsLease Operating Expenses
Production costs include lease operating expenses, production taxes, transportation, gathering and processing costs and certain production and engineering staff-related overhead costs, as well as other costs to operate wells and pipelines as follows:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in millions) |
| | | | | | | |
Lease operating expenses | $ | 12.4 |
| | $ | 10.7 |
| | $ | 40.7 |
| | $ | 29.7 |
|
Production taxes | 5.5 |
| | 8.8 |
| | 13.2 |
| | 22.7 |
|
Transportation, gathering and processing expenses | 3.9 |
| | 1.2 |
| | 6.6 |
| | 3.3 |
|
Overhead and other production expenses
| 3.7 |
| | 2.1 |
| | 10.6 |
| | 9.0 |
|
Total production costs | $ | 25.5 |
| | $ | 22.8 |
| | $ | 71.1 |
| | $ | 64.7 |
|
Total production costs per Boe | $ | 5.89 |
| | $ | 9.67 |
| | $ | 6.72 |
| | $ | 9.62 |
|
| | | | | | | |
Lease operating expenses. The $1.7$1.0 million increase in lease operating expenses during the three months ended SeptemberJune 30, 20152016 compared to the three months ended SeptemberJune 30, 20142015 was primarily due to an increase of $0.8$0.4 million for environmental remediationin contract labor, $0.3 million in leased generators and $0.9 million in other lease operating expenses, offset in part by a decrease of $0.5 million in regulatory compliance projects and $0.8 million for additional wages and employee benefits, including costs for additional contract labor. The $11.0 million increase in leaseprojects. Lease operating expenses during the ninesix months ended SeptemberJune 30, 2016 were comparable to the six months ended June 30, 2015. Lease operating expenses per Boe decreased 29% and 34% to $2.63 and $2.97 during the three and six months ended June 30, 2016, respectively, compared to $3.71 and $4.52 during the three and six months ended June 30, 2015, compared to the nine months ended September 30, 2014 was primarily due to an increase of $5.4 million for environmental remediation and regulatory compliance projects, an increase of $2.7 million for additional wages and employee benefits, including costs for additional contract labor, $1.3 million forrespectively. The significant decreases in lease operating expenses incurred onexpense per Boe were the increasing numberresult of non-operated wells in the Wattenberg Fieldproduction growth of 54% and $0.7 million for additional costs pertaining to water hauling and disposal.56%, respectively.
Production taxes. Taxes
Production taxes are directly related to crude oil, natural gas and NGLs sales. The $3.3$2.2 million or 38%, decreaseand $2.4 million increases in production taxes forduring the three and six months ended SeptemberJune 30, 20152016, respectively, compared to the three and six months ended SeptemberJune 30, 2014, was2015 were primarily related to the 13% decrease14% and 9% increases in crude oil, natural gas and NGLs sales, respectively, and lower production tax rates. Similarly, the $9.5 million, or 42%, decrease in2015 production taxes for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014, was primarilyreflecting downward adjustments related to the 26% decreasead valorem rates for production in crude oil, natural gas2014 and NGLs sales and lower production tax rates.2015.
Transportation, Gathering and Processing Expenses
The $3.2 million and $5.9 million increases in transportation, gathering and processing expenses. The $2.7 million and $3.3 million increases during the three and ninesix months ended SeptemberJune 30, 2015,2016, respectively, compared to the three and ninesix months ended SeptemberJune 30, 2014 was2015 were mainly attributable to oil transportation cost on the White Cliffs pipelineand Saddle Butte pipelines as we began delivering crude oil at the beginning ofon these pipelines in July 2015.2015 and December 2015, respectively. We expect to continue to incur these oil transportation costs pursuant to our long-term firm transportation agreement.
Overhead and other production expenses. The $1.6 million increase during the three months ended September 30, 2015 compared to the three months ended September 30, 2014 was mainly attributable to an increase of $0.8 million in adjustments to the value of our crude oil inventory at the lower of cost and net realizable value, the majority of which was attributable to the value of inventory for the White Cliffs pipeline line fill and an increase of $0.4 million in expired prepaid well costs. The $1.6 million increase during the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014 was mainly attributable to an increase of $1.1 million in expired prepaid well costs and an increase of $0.3 million in adjustments to value our crude oil inventory at the lower of cost and net realizable value.agreements.
Commodity Price Risk Management, Net
We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our natural gas and crude oil production at prices similar to the indexes inherent in our derivative instruments, adjusted for certain fees and surcharges stipulated in the applicable sales agreements, we ultimately realize a price, before contract fees, related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps.swaps, less deductions. See Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for a detailed presentation of our derivative positions as of June 30, 2016.
Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments and the change in fair value of unsettled derivatives related to our crude oil and natural gas production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for additional details of our derivative financial instruments.
Net settlements are primarily the result of crude oil and natural gas index prices at maturity of our derivative instruments compared to the respective strike prices. Net change in fair value of unsettled derivatives is comprised of the net asset increase or decrease in the beginning-of-periodbeginning-
of-period fair value of derivative instruments that settled during the period and the net change in fair value of unsettled derivatives during the period. The corresponding impact of settlement of the derivative instruments that settled during the period is included in net settlements for the period as discussed above. Net change in fair value of unsettled derivatives during the period is primarily related to shifts in the crude oil and natural gas forward curves and changes in certain differentials. See Note 4, Derivative Financial Instruments, to our consolidated financial statements included elsewhere in this report for a detailed description of net settlements on our various derivatives.
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, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in millions) |
Commodity price risk management gain, net: | | | | | | | |
Net settlements: | | | | | | | |
Crude oil | $ | 60.7 |
| | $ | (4.8 | ) | | $ | 142.4 |
| | $ | (17.6 | ) |
Natural gas | 7.3 |
| | 0.3 |
| | 20.1 |
| | (3.9 | ) |
Total net settlements | 68.0 |
| | (4.5 | ) | | 162.5 |
| | (21.5 | ) |
Change in fair value of unsettled derivatives: | | | | | | | |
Reclassification of settlements included in prior period changes in fair value of derivatives | (48.1 | ) | | 12.8 |
| | (140.2 | ) | | 11.2 |
|
Crude oil fixed price swaps | 50.4 |
| | 63.5 |
| | 51.4 |
| | 16.5 |
|
Crude oil collars | 28.5 |
| | 10.2 |
| | 28.6 |
| | 3.3 |
|
Natural gas fixed price swaps | 19.5 |
| | 6.5 |
| | 31.0 |
| | 2.4 |
|
Natural gas basis swaps | (1.0 | ) | | — |
| | (2.4 | ) | | — |
|
Natural gas collars | 6.2 |
| | 1.7 |
| | 10.3 |
| | 0.8 |
|
Net change in fair value of unsettled derivatives | 55.5 |
| | 94.7 |
| | (21.3 | ) | | 34.2 |
|
Total commodity price risk management gain, net | $ | 123.5 |
| | $ | 90.2 |
| | $ | 141.2 |
| | $ | 12.7 |
|
Natural Gas Marketing
Fluctuations in our natural gas marketing segment's income contribution are primarily due to fluctuations in commodity prices, cash settlements upon maturity of derivative instruments and the change in fair value of unsettled derivatives, and, to a lesser extent, volumes sold and purchased.
The following table presents the components of sales from and costs of natural gas marketing:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
| (in millions) |
Natural gas sales revenue | $ | 2.4 |
| | $ | 12.9 |
| | $ | 8.0 |
| | $ | 62.9 |
|
Net settlements from derivatives | 0.2 |
| | 0.2 |
| | 0.6 |
| | (0.4 | ) |
Net change in fair value of unsettled derivatives
| — |
| | 0.2 |
| | (0.3 | ) | | 0.1 |
|
Total sales from natural gas marketing | 2.6 |
| | 13.3 |
| | 8.3 |
| | 62.6 |
|
| | | | | | | |
Costs of natural gas purchases | 2.4 |
| | 12.6 |
| | 8.0 |
| | 61.8 |
|
Net settlements from derivatives | 0.2 |
| | 0.2 |
| | 0.5 |
| | (0.5 | ) |
Net change in fair value of unsettled derivatives
| — |
| | 0.2 |
| | (0.3 | ) | | 0.2 |
|
Other | 0.2 |
| | 0.3 |
| | 0.7 |
| | 1.1 |
|
Total costs of natural gas marketing | 2.8 |
| | 13.3 |
| | 8.9 |
| | 62.6 |
|
| | | | | | | |
Natural gas marketing contribution margin | $ | (0.2 | ) | | $ | — |
| | $ | (0.6 | ) | | $ | — |
|
| | | | | | | |
Natural gas sales revenue and cost of natural gas purchases decreased in the three and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014, as our Gas Marketing segment has scaled down following the divestiture of our Appalachian Basin natural gas properties. Our Gas Marketing segment sold approximately 1.1 Bcf of natural gas at an average price of $1.14 per Mcf during the three months ended September 30, 2015, compared to approximately 5.0 Bcf of natural gas at an average price of $2.35 per Mcf during the three months ended September 30, 2014. Our Gas Marketing segment sold approximately 3.3 Bcf of natural gas at an average price of $1.42 per Mcf during the nine months ended September 30, 2015, compared to approximately 16.5 Bcf of natural gas at an average price of $3.62 per Mcf during the nine months ended September 30, 2014.
Derivative instruments related to natural gas marketing include both physical and cash-settled derivatives. We offer fixed-price
derivative contracts for the purchase or sale of physical natural gas and enter into cash-settled derivative positions with counterparties in order
to offset those same physical positions. |
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
| (in millions) |
Commodity price risk management gain (loss), net: | | | | | | | |
Net settlements: | | | | | | | |
Crude oil | $ | 38.7 |
| | $ | 37.0 |
| | $ | 92.0 |
| | $ | 81.7 |
|
Natural gas | 14.6 |
| | 7.1 |
| | 28.1 |
| | 12.7 |
|
Total net settlements | 53.3 |
| | 44.1 |
| | 120.1 |
| | 94.4 |
|
Change in fair value of unsettled derivatives: | | | | | | | |
Reclassification of settlements included in prior period changes in fair value of derivatives | (60.8 | ) | | (54.3 | ) | | (115.5 | ) | | (89.4 | ) |
Crude oil fixed price swaps | (38.2 | ) | | (24.5 | ) | | (43.9 | ) | | (1.5 | ) |
Crude oil collars | (19.6 | ) | | (8.8 | ) | | (18.9 | ) | | (0.5 | ) |
Natural gas fixed price swaps | (23.1 | ) | | (2.2 | ) | | (19.4 | ) | | 12.1 |
|
Natural gas basis swaps | — |
| | (2.5 | ) | | (0.4 | ) | | (2.0 | ) |
Natural gas collars | (4.4 | ) | | (0.8 | ) | | (3.7 | ) | | 4.5 |
|
Net change in fair value of unsettled derivatives | (146.1 | ) | | (93.1 | ) | | (201.8 | ) | | (76.8 | ) |
Total commodity price risk management gain (loss), net | $ | (92.8 | ) | | $ | (49.0 | ) | | $ | (81.7 | ) | | $ | 17.6 |
|
Impairment of Crude OilProperties and Natural Gas PropertiesEquipment
The following table sets forth the major components of our impairmentsimpairment of crude oilproperties and natural gas propertiesequipment expense:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in thousands) | (in millions) |
| | | | | | | | | | | | | | |
Impairment of proved and unproved properties | $ | 150.3 |
| | $ | — |
| | $ | 150.3 |
| | $ | — |
| $ | 1.1 |
| | $ | 1.6 |
| | $ | 2.1 |
| | $ | 1.9 |
|
Amortization of individually insignificant unproved properties | 3.2 |
| | 1.1 |
| | 8.5 |
| | 2.8 |
| 0.1 |
| | 2.8 |
| | 0.1 |
| | 5.3 |
|
Other | — |
| | 0.8 |
| | — |
| | 0.8 |
| |
Total impairment of crude oil and natural gas properties | $ | 153.5 |
| | $ | 1.9 |
| | $ | 158.8 |
| | $ | 3.6 |
| |
Impairment of crude oil and natural gas properties
| | 1.2 |
| | 4.4 |
| | 2.2 |
| | 7.2 |
|
Land and buildings | | 3.0 |
| | — |
| | 3.0 |
| | — |
|
Impairment of properties and equipment | | $ | 4.2 |
| | $ | 4.4 |
| | $ | 5.2 |
| | $ | 7.2 |
|
Impairment of proved and unproved properties.properties Due to a significant decline in commodity prices and a decrease in net-back realizations, we experienced a triggering event that required us to assess our crude oil and natural gas properties for possible impairment during. Amounts represent the third quarterwrite-down of 2015. As a result of our assessment, we recorded an impairment charge 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. The impairment charge representedproperties as the amount by whichexpected development date for these locations are beyond the carrying value of these crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value of approximately $27.9 million was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. Additionally, as a resultlimits of the current outlook for future commodity prices, 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.SEC five-year rule. Further deterioration of commodity prices could result in additional impairment charges to our crude oil and natural gas properties.
Amortization of individually insignificant unproved properties. The period-over-period increases were primarily relatedAmounts relate to a higher number of insignificant leases that were subject to amortization. The decreases in amortization primarilyduring the three and six months ended June 30, 2016 compared to the three and six months ended June 30, 2015, were due to an impairment in the third quarter of 2015 that significantly reduced the carrying value of our Utica Shale where we have altered drilling plans dueleases.
Land and buildings. The impairment charge represents the excess of the carrying value over the estimated fair value, less the cost to lower crude oil pricessell, of a field operating facility in Greeley, Colorado, and as12 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 result, expect certain leases to expire.Level 3 input.
General and Administrative Expense
General and administrative expense decreased $16.1increased $2.9 million to $18.5$23.6 million for the three months ended SeptemberJune 30, 20152016 compared to $34.6$20.7 million for the three months ended SeptemberJune 30, 2014.2015. The decreaseincrease was primarily attributable to $16.2 million recorded during the three months ended September 30, 2014 in connection with certain partnership-related class action litigation and estimates relating to litigation arising from bankruptcy proceedings of certain affiliated partnerships.
General and administrative expense decreased $40.6 million to $55.9 million for the nine months ended September 30, 2015 compared to $96.5 million for the nine months ended September 30, 2014. The decrease was primarily attributable to $40.3 million recorded during the nine months ended September 30, 2014 in connection with certain partnership-related class action litigation and estimates relating to litigation arising from bankruptcy proceedings of certain affiliated partnerships and a $3.0 million decrease in costs for legal and other professional services during the nine months ended September 30, 2015. The decreases were offset in part by a $2.5$2.7 million increase in payroll and employee benefits, duringof which $1.3 million was stock-based compensation.
General and administrative expense increased $4.6 million to $46.4 million for the ninesix months ended SeptemberJune 30, 2016 compared to $41.8 million for the six months ended June 30, 2015. The increase was primarily attributable to a $3.3 million increase in payroll and employee benefits, of which $1.6 million was stock-based compensation, a $0.7 million increase in costs for consulting and other professional services and a $0.4 million increase in marketing and government relations activities.
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 $79.8$106.1 million and $203.5$202.4 million for the three and ninesix months ended SeptemberJune 30, 2015, respectively,2016 compared to $48.7$69.0 million and $139.1$123.7 million for the three and ninesix months ended SeptemberJune 30, 2014.2015. The period-over-period increases were comprised of increases of $40.8 millionchange in DD&A expense related to crude oil and $80.5 millionnatural gas properties was primarily due to higher production during the three and nine months ended September 30, 2015, respectively, offset in part by decreases of $9.7 million and $16.1 million due to lower weighted-average depreciation, depletion and amortization rates during the three and nine months ended September 30, 2015, respectively.following:
|
| | | | | | | | |
| | June 30, 2016 |
| | Three Months Ended | | Six Months Ended |
| | (in millions) |
Increase in production | | $ | 39.0 |
| | $ | 72.8 |
|
Increase (decrease) in weighted-average depreciation, depletion and amortization rates | | (1.9 | ) | | 5.9 |
|
Total increase in DD&A expense related to crude oil and natural gas properties | | $ | 37.1 |
| | $ | 78.7 |
|
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, | | Three Months Ended June 30, | | Six Months Ended June 30, |
Operating Region/Area | | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 |
| | (per Boe) | | (per Boe) |
Wattenberg Field | | $ | 19.10 |
| | $ | 19.56 |
| | $ | 19.92 |
| | $ | 19.78 |
| | $ | 20.73 |
| | $ | 21.09 |
| | $ | 21.19 |
| | $ | 20.50 |
|
Utica Shale | | 10.08 |
| | 32.98 |
| | 11.49 |
| | 30.75 |
| | 13.84 |
| | 14.23 |
| | 11.16 |
| | 12.27 |
|
Total weighted-average | | 18.44 |
| | 20.70 |
| | 19.22 |
| | 20.73 |
| | 20.41 |
| | 20.48 |
| | 20.72 |
| | 19.76 |
|
The decrease in the Utica Shaleweighted-average DD&A expense rate duringrates for the three and ninesix months ended SeptemberJune 30, 2015 compared2016 were comparable to the three and ninesix months ended SeptemberJune 30, 2014 was primarily due to the effect of an impairment recorded in December 2014 to write-down certain capitalized well costs on our Utica Shale proved producing properties, which lowered the net book value of the properties by approximately $112.6 million.2015.
Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $1.2$0.9 million and $3.4$2.0 million for the three and ninesix months ended SeptemberJune 30, 2015,2016, respectively, compared to $1.0$1.1 million and $3.1$2.2 million for the three and ninesix months ended SeptemberJune 30, 2014,2015, respectively.
Provision for Uncollectible Notes Receivable
A provision for uncollectible notes receivable of $44.7 million was recorded during the six months ended June 30, 2016 to impair two third-party notes receivable whose collection is not reasonably assured. See Note 3, Fair Value of Financial Instruments - Notes Receivable, to our condensed consolidated financial statements included elsewhere in this report for additional information.
Interest Expense
Interest expense decreased $0.9 million and $0.7 million during the three and six months ended June 30, 2016 compared to the three and six months ended June 30, 2015. The decreases were primarily attributable to decreases in interest on the Convertible Notes as they matured in May 2016.
Interest Income
Interest income increased to $1.4decreased $1.0 million forand $0.5 million during the three and six months ended SeptemberJune 30, 2016 compared to the three and six months ended June 30, 2015, mainly attributable to $1.1 million ofas we ceased recognizing non-cash interest income recognized during the three months ended September 30, 2015 on a promissory note received as part of the consideration for the sale of our entire 50% ownership interest in PDCM, of which $0.8 million was paid-in-kind and added to the principal amount of the promissory note.two third-party notes receivable.
Interest income increased to $3.6 million for the nine months ended September 30, 2015 compared to $0.3 million for the nine months ended September 30, 2014, mainly attributable to $3.4 million
Interest Expense
Interest expense increased $0.3 million to $12.1 million for the three months ended September 30, 2015 compared to $11.8 million for the three months ended September 30, 2014. The increase is primarily comprised of a $0.2 million increase due to higher average borrowings on our revolving credit facility during the three months ended September 30, 2015.
Interest expense decreased $0.8 million to $35.4 million for the nine months ended September 30, 2015 compared to $36.2 million for the nine months ended September 30, 2014. The decrease is primarily comprised of a $2.0 million decrease attributable to an increase in capitalized interest, offset in part by a $0.9 million increase due to higher average borrowings on our revolving credit facility during the nine months ended September 30, 2015.
Provision for Income Taxes
See Note 6, Income Taxes, to the accompanying condensed consolidated financial statements included elsewhere in this report for a discussion of the changes in our effective tax rate for the three and ninesix months ended SeptemberJune 30, 20152016 compared to the three and ninesix months ended SeptemberJune 30, 2014.2015. The effective tax rate of 33.8%37.9% and 36.3%37.5% benefit on loss from continuing operations for the three and ninesix months ended SeptemberJune 30, 2015,2016, respectively, areis based on forecasted pre-tax loss for the year adjusted for permanent differences. The forecasted full year effective tax rate has been applied to the quarter-to-date and year-to-date pre-tax loss resulting in a tax benefit for the respective periods.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.
Discontinued Operations
In October 2014, we completed the sale of our entire 50% ownership interest in PDCMNet deferred income tax liability at June 30, 2016 decreased $102.3 million compared to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million, comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million. The transaction included the buyer's assumption of our share of the firm transportation commitment relatedDecember 31, 2015. This decrease is primarily attributable to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions forsignificant positive net settlements from derivatives during the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million. The divestiture represented a strategic shift in our operations. Accordingly, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the condensed consolidated statement of operations for the three and ninesix months ended SeptemberJune 30, 2014.
See Note 13, Assets Held for Sale, Divestitures2016 and Discontinued Operations to the accompanying condensed consolidated financial statements included elsewheresignificant negative net change in this report for additional information regarding the salefair value of our ownership interest in PDCM.
The table below presents production data related to PDCM's Marcellus Shale assets that have been divested and that are classified as discontinued operations:
|
| | | | | | |
| | September 30, 2014 |
Discontinued Operations | | Three Months Ended | | Nine Months Ended |
Production | | | | |
Natural gas (MMcf)
| | 2,097.4 |
| | 6,557.9 |
|
Crude oil equivalent (MBoe)
| | 349.6 |
| | 1,093.0 |
|
unsettled derivatives held at June 30, 2016.
Net Income (Loss)/Loss/Adjusted Net Income (Loss)
Net loss for the three and ninesix months ended SeptemberJune 30, 20152016 was $41.5$95.5 million and $71.3$167.0 million compared to net incomeloss of $54.0$46.9 million and $23.7$29.8 million for the three and ninesix months ended SeptemberJune 30, 2014.2015. Adjusted net loss, a non-U.S. GAAP financial measure, was $75.9$5.1 million and $41.9 million for the three and six months ended SeptemberJune 30, 20152016 compared to adjusted net lossincome of $5.7$10.8 million and $17.9 million for the same prior year period. Adjusted net loss was $58.1 million for the nine months ended September 30, 2015 compared to adjusted net income of $2.4 million for the same prior year period.periods. The quarter-over-quarter and year-over-year changes in net incomeloss are discussed above, with the most significant changes related to the increasesdecrease in impairment of crude oil and natural gas properties, DD&A expense and commodity price risk management activity income and the decreaseincrease in crude oil, natural gas and NGLs sales and generalDD&A expense. The year-over-year changes in net loss are discussed above, with the most significant changes related to the decrease in commodity price risk management activity income and administrative expense.the increase in crude oil, natural gas and NGLs sales, DD&A expense and provision for uncollectible notes receivable. These same reasons for changechanges similarly impacted adjusted net income (loss), with the exception of the tax effected net change in fair value of unsettled derivatives, adjusted for taxes, as this amount is not included in the total.derivatives. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of this non-U.S. GAAP financial measure.
Financial Condition, Liquidity and Capital Resources
Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in debt and equity market transactions and asset sales. For the ninesix months ended SeptemberJune 30, 2015,2016, our primary sources of liquidity were the net proceeds received from the March 2016 public offering of our common stock of $296.6 million and net cash flows from operating activities of $283.0 million and the proceeds received from the March 2015 public offering of our common stock of approximately $203$197.8 million. We used a portion of the net proceeds of the offering to repay all amounts then outstanding on our revolving credit facility, the principal amounts owed upon the maturity of the Convertible Notes in May 2016, and usedretained the remaining amounts to fund a portion of our capital program.remainder 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 derivatives.derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. For instruments that mature in three years or less, our debt covenants restrict us from entering into hedges that would exceed 85% of our expected future production from total proved reserves for such related time period (proved developed producing, proved developed non-producing and proved undeveloped). For instruments that mature later than three years, but no more than our designated maximum maturity, our debt covenants limit us from entering into hedges that would exceed 85% of our expected future production from proved developed producing properties during that time period. In addition, weWe may choose not to hedge the maximum amounts permitted under our covenants. Therefore, we may still have significant fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. Given current commodity prices and our hedge position, we expect that positive net settlements on our derivative positions will continue to be a significant positive component of our 20152016 cash flows from operations. As of June 30, 2016, the fair value of our derivatives was a net asset of $61.9 million. Based on the forward pricing strip at June 30, 2016, we would expect positive net settlements totaling approximately $75.9 million during the second half of 2016. However, based upon our current hedge position and assuming current strip pricing, during periods subsequent to 2016 our derivatives may no longer be a significant source of cash flow, and may result in cash outflows. For the six months ended June 30, 2016 and 2015, net settled derivatives comprised approximately 61% and 65%, 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.
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 SeptemberJune 30, 2015,2016, we had a working capital deficit of $9.5$131.9 million compared to a surplus of $30.3$30.7 million at December 31, 2014.2015. The decreaseincrease in working capital to a deficit as of SeptemberJune 30, 20152016 is primarily the result of classifying as a current liabilityan increase in cash and cash equivalents and the carrying valuerepayment of the Convertible Notes netin May 2016, offset in part by a decrease in the fair value of discount, as the stated maturity of the Convertible Notes is May 2016.unsettled derivatives.
2016, we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of securities. We ended September 2015June 2016 with cash and cash equivalents of $3.7$109.1 million and availability under our revolving credit facility of $388.3$438.3 million, for a total liquidity position of $392.0$547.4 million, compared to $398.4$402.2 million at December 31, 2014.2015. These amounts exclude an additional $250 million available under our revolving credit facility, subject to certain terms and conditions of the credit agreement. The decreaseincrease in liquidity of $6.4$145.2 million, or 1.6%36.1%, during the six months ended June 30, 2016 was primarily attributable to capital expendituresnet cash flows from operating activities of $489.0$197.8 million duringand net cash flows from financing activities of $141.3 million, primarily due to the nine months ended September 30, 2015, which was financed by approximately $203 million received from the
March 2016 public offering of our common stock, andoffset in part by cash flows provided by operating activitiespaid for capital expenditures of $283.0$235.7 million. Our revised forecast estimatesliquidity position was reduced by the cash payment of approximately $115 million upon the maturity of our adjusted cash flows from operations will range from $400 million to $420 millionConvertible Notes in 2015, based on estimated NYMEX crude oil and natural gas prices, before the effects of differentials or hedges, of $48.98 per barrel of crude oil, $2.87 per Mcf of natural gas and $9.61 per barrel of NGLs. Due to the derivative hedges in place as of September 30, 2015, a $10 per barrel change in the price of crude oil would change our estimated adjusted cash flows from operations for the remainder of 2015 by approximately $4 million to $8 million. Based on our current commodity mix and hedge position, we estimate that a decline in the price of natural gas will not have a material impact on our adjusted cash flows from operations in 2015.May 2016. With our current derivative position, liquidity position and expected cash flows from operations, we believe that we have sufficient capital to fund our development plan.planned drilling operations for the next 12 months. We cannot, however, assure sources of capital available to us in the past will be available to us in the future.
In March 2015, we filed an automatic shelf registration statement on Form S-3 with the SEC. Effective upon filing, the shelf provides for the potential sale of an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants or purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital and to have the flexibility to raise such funds in one or more offerings should we perceive market conditions to be favorable. Pursuant to this shelf registration, we sold approximately four million shares of our common stock in March 2015 in an underwritten public offering at a price to us of $50.73 per share and approximately $50.73six million shares of our common stock in March 2016 in an underwritten public offering at a price to us of $50.11 per share.
In recent periods, including the nine months ended September 30, 2015, we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of securities. We cannot, however, assure this will continue to be the case in the future. In light of recent weakened commodity prices, we continue to monitor market conditions and their potential impact on each of our revolving credit facility lenders, many of which are counterparties in our derivative transactions. Our revolving credit facility borrowing base is subject to a redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. In September 2015,May 2016, we completed the semi-annual redetermination of our revolving credit facility by the lenders, which resulted in the reaffirmation of our borrowing base at $700 million. Further, we entered into a Second Amendment to Third Amended and Restated Credit Agreement that extended the maturity date of our revolving credit facility to May 2020. However, we have elected to maintain the aggregate commitment level at $450 million. The maturity date of the revolving credit facility is May 2020. We had $50.0 millionno outstanding balance on our revolving credit facility as of SeptemberJune 30, 2015.2016. While we have added and expect to continue to add producing reserves through our drilling operations, the effect of any such reserve additions on our borrowing base could be offset by other factors including, among other things, a prolonged period of depressed commodity prices or regulatory pressure on lenders to reduce their exposure to exploration and production companies.
Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.25 times the trailing 12 months earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled derivatives, exploration expense, gains (losses) on sales of assets and other non-cash, extraordinary or non-recurring gains (losses) ("EBITDAX") and (ii) an adjusted current ratio of at least 1.0 to 1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of crude oil and natural gas derivative instruments. Additionally, available borrowings under our revolving credit facility are added to the current asset calculation and the current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At SeptemberJune 30, 2015,2016, we were in compliance with all debt covenants with a 1.61.0 times debt to EBITDAX ratio and a 1.54.0 to 1.0 current ratio. We expect to remain in compliance throughout the next year.
The indenture governing our 7.75% senior notes due 2022 contains customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. At SeptemberJune 30, 2015,2016, we were in compliance with all covenants and expect to remain in compliance throughout the next year.
The conversion rights on our Convertible Notes could be triggered prior to the maturity date. We have currently elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. In the event that a holder elects to convert its note, we expect to fund the cash settlement of any such conversion from working capital and/or borrowings under our revolving credit facility. The conversion right is not expected to have a material impact on our financial position. The Convertible Notes were not convertible at the option of holders as of the date of this filing.
See Part I, Item 3, Quantitative and Qualitative Disclosures about Market Risk, for our discussion of credit risk.
Cash Flows
Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities increased by $81.0$51.3 million for the ninesix months ended SeptemberJune 30, 2015,2016 compared to the ninesix months ended SeptemberJune 30, 2014. The increase in cash provided by operating activities was2015, primarily due to the increaseincreases in net settlements from our derivative positions of $183.9$25.7 million and a decrease in general and administrative expense of $40.7 million. The increase was partially offset by the decrease in crude oil, natural gas and NGLs sales of $96.1$15.2 million and the increase in changes in assets and liabilities of $32.3$18.6 million related to the timing of cash payments and receiptsreceipts. These increases were offset in part by the increase in transportation, gathering and a $9.6 million decrease in cash flows from discontinued operating activities.processing expenses of $5.9 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 $113.4$32.8 million during the ninesix months ended SeptemberJune 30, 2015,2016, compared to the ninesix months ended SeptemberJune 30, 2014.2015. The increase was primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of assets and liabilities. Adjusted EBITDA, a non-U.S. GAAP financial measure, increaseddecreased by $109.8$16.3 million during the ninesix months ended SeptemberJune 30, 20152016 compared to the ninesix months ended SeptemberJune 30, 2014.2015. The increasedecrease was primarily the result of recording a provision for uncollectible notes receivable of $44.7 million and the increase in transportation, gathering and processing expenses of $5.9 million and general and administrative expense of $4.6 million, offset in part by increases in net settlements from our derivative positions of $183.9$25.7 million and a decrease in general and administrative expense of $40.7 million. The increase was partially offset by the decrease in crude oil, natural gas and NGLs sales of $96.1 million, a $12.6 million decrease in contribution margins from discontinued operations and a $6.5 million increase in production costs.$15.2 million. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of non-U.S. GAAP financial measures.
Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital expenditures. We would not be able to maintain our current level
Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. During the nine months ended September 30, 2015, our drilling program consisted of five drilling rigs operating in the horizontal Niobrara and Codell plays in our Wattenberg Field. Net cash used in investing activities of $488.7$230.8 million during the ninesix months ended SeptemberJune 30, 20152016 was primarily related to cash utilized for our drilling operations. Duringoperations, including completion activities. For the third quarter of 2015,full year 2016, we expect that our cash flows from operations approximatedwill approximate our cash flows from investing activities and we expect the same for the remainder of 2015.activities.
Financing Activities. Net cash from financing activities for the ninesix months ended SeptemberJune 30, 2015 increased2016 decreased by approximately $120.3$55.5 million compared to the ninesix months ended SeptemberJune 30, 2014.2015. Net cash from financing activities of $193.3$141.3 million for the ninesix months ended SeptemberJune 30, 20152016 was primarily related to the $202.9$296.6 million received from the issuance of our common stock in March 2015,2016, partially offset by the $115.0 million payment of principal amounts owed upon the maturity of the Convertible Notes and net payments of approximately $6.0$37.0 million to pay down amounts borrowed under our revolving credit facility.
Drilling Activity
The following table presents our net developmental drilling activity for the periods shown. Productive wells consist of wells spud, turned-in-line and producing during the period. In-process wells represent wells that have been spud, drilled or are waiting to be completed and/or for gas pipeline connection during the period.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net Drilling Activity |
| | Three Months Ended June 30, | | Six Months Ended June 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 | | 27.7 | | 47.2 | | 0.4 | | 35.4 | | 45.9 | | 1.0 | | 52.6 |
| | 47.2 |
| | 0.4 | | 48.5 |
| | 45.9 |
| | 1.0 |
|
Wattenberg Field, non-operated wells | | 1.7 | | 7.7 | | — | | 1.6 | | 4.9 | | — | | 3.2 |
| | 7.7 |
| | — | | 4.2 |
| | 4.9 |
| | — |
|
Utica Shale | | 2.8 | | 1.7 | | — | | 3.0 | | — | | — | | 2.8 |
| | 1.7 |
| | — | | 3.0 |
| | — |
| | — |
|
Total drilling activity | | 32.2 | | 56.6 | | 0.4 | | 40.0 | | 50.8 | | 1.0 | | 58.6 |
| | 56.6 |
| | 0.4 |
| | 55.7 |
| | 50.8 |
| | 1.0 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net Drilling Activity |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2015 | | 2014 | | 2015 | | 2014 |
Operating Region/Area | | Productive | | In-Process | | Dry (1) | | Productive | | In-Process | | Productive | | In-Process | | Dry (1) | | Productive | | In-Process | | Dry (1) |
Development Wells | | | | | | | | | | | | | | | | | | | | | | |
Wattenberg Field | | 27.7 | | 57.7 | | 1.1 | | 12.1 | | 48.9 | | 80.4 |
| | 57.7 |
| | 2.1 |
| | 48.3 |
| | 48.9 |
| | 1.7 |
|
Utica Shale | | — | | — | | — | | 2.0 | | 3.7 | | 3.0 |
| | — |
| | — |
| | 4.0 |
| | 3.7 |
| | 1.0 |
|
Marcellus Shale (2) | | — | | — | | — | | — | | — | | — |
| | — |
| | — |
| | 2.0 |
| | — |
| | — |
|
Total drilling activity | | 27.7 | | 57.7 | | 1.1 | | 14.1 | | 52.6 | | 83.4 |
| | 57.7 |
| | 2.1 |
| | 54.3 |
| | 52.6 |
| | 2.7 |
|
______________
(1) Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
(2) Represents PDCM's drilling activity. On October 14, 2014, we closed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations to our condensed consolidated financial statements included elsewhere in this report for additional information.
Off-Balance Sheet Arrangements
At SeptemberJune 30, 20152016, we had no off-balance sheet arrangements, as defined under SEC rules, that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Commitments and Contingencies
See Note 10, Commitments and Contingencies, to the accompanying condensed consolidated financial statements included elsewhere in this report.
Recent Accounting Standards
See Note 2, Summary of Significant Accounting Policies, to the accompanying condensed consolidated financial statements included elsewhere in this report.
Critical Accounting Policies and Estimates
The preparation of the accompanying condensed consolidated financial statements in conformity with U.S. GAAP required management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenue and expenses.
There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the consolidated financial statements and accompanying notes contained in our 20142015 Form 10-K filed with the SEC on February 19, 2015.22, 2016.
Reconciliation of Non-U.S. GAAP Financial Measures
We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDA," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities, and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs and related operational factors, without regard to whether the related asset or liability was received
or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has been only a timing issue from one period to the next as we have not had significant accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. See the condensed consolidated statements of cash flows in the accompanying condensed consolidated financial statements included elsewhere in this report.
Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives and net settlements on commodity derivatives, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of unsettled derivatives. Additionally, other items which are not indicative of future results may be excluded to clearly identify operating trends.
Adjusted EBITDA. We define adjusted EBITDA as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of crude oilproperties and natural gas properties,equipment, depreciation, depletion and amortization expense and accretion of asset retirement obligations, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDA is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), and should not be considered an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDA includes certain non-cash costs incurred by the Company and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDA is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts and others to analyze such things as:
operating performance and return on capital as compared to our peers;
financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis;
our ability to generate sufficient cash to service our debt obligations; and
the viability of acquisition opportunities and capital expenditure projects, including the related rate of return.
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 June 30, | | Six Months Ended June 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Adjusted cash flows from operations: | | | | | | | | | | | | | | |
Adjusted cash flows from operations | $ | 122.7 |
| | $ | 55.5 |
| | $ | 293.6 |
| | $ | 180.2 |
| $ | 112.6 |
| | $ | 96.9 |
| | $ | 203.6 |
| | $ | 170.8 |
|
Changes in assets and liabilities | 13.8 |
| | 14.9 |
| | (10.6 | ) | | 21.8 |
| (16.0 | ) | | (32.3 | ) | | (5.8 | ) | | (24.3 | ) |
Net cash from operating activities | $ | 136.5 |
| | $ | 70.4 |
| | $ | 283.0 |
| | $ | 202.0 |
| $ | 96.6 |
| | $ | 64.6 |
| | $ | 197.8 |
| | $ | 146.5 |
|
| | | | | | | | | | | | | | |
Adjusted net income (loss): | | | | | | | | | | | | | | |
Adjusted net income (loss) | $ | (75.9 | ) | | $ | (5.7 | ) | | $ | (58.1 | ) | | $ | 2.4 |
| $ | (5.1 | ) | | $ | 10.8 |
| | $ | (41.9 | ) | | $ | 17.9 |
|
Gain on commodity derivative instruments | 123.5 |
| | 92.2 |
| | 141.2 |
| | 11.6 |
| |
Gain (loss) on commodity derivative instruments | | (92.7 | ) | | (49.0 | ) | | (81.7 | ) | | 17.6 |
|
Net settlements on commodity derivative instruments | (68.0 | ) | | 4.1 |
| | (162.5 | ) | | 22.7 |
| (53.3 | ) | | (44.1 | ) | | (120.2 | ) | | (94.5 | ) |
Tax effect of above adjustments | (21.1 | ) | | (36.6 | ) | | 8.1 |
| | (13.0 | ) | 55.6 |
| | 35.4 |
| | 76.8 |
| | 29.2 |
|
Net income (loss) | $ | (41.5 | ) | | $ | 54.0 |
| | $ | (71.3 | ) | | $ | 23.7 |
| |
Net loss | | $ | (95.5 | ) | | $ | (46.9 | ) | | $ | (167.0 | ) | | $ | (29.8 | ) |
| | | | | | | | | | | | | | |
Adjusted EBITDA to net income (loss): | | | | | | | | |
Adjusted EBITDA to net loss: | | | | | | | | |
Adjusted EBITDA | $ | 128.6 |
| | $ | 62.6 |
| | $ | 311.6 |
| | $ | 201.8 |
| $ | 115.7 |
| | $ | 102.6 |
| | $ | 168.7 |
| | $ | 185.0 |
|
Gain on commodity derivative instruments | 123.5 |
| | 92.2 |
| | 141.2 |
| | 11.6 |
| |
Gain (loss) on commodity derivative instruments | | (92.7 | ) | | (49.0 | ) | | (81.7 | ) | | 17.6 |
|
Net settlements on commodity derivative instruments | (68.0 | ) | | 4.1 |
| | (162.5 | ) | | 22.7 |
| (53.3 | ) | | (44.1 | ) | | (120.2 | ) | | (94.5 | ) |
Interest expense, net | (10.7 | ) | | (12.4 | ) | | (31.8 | ) | | (37.9 | ) | (10.5 | ) | | (10.4 | ) | | (20.8 | ) | | (21.1 | ) |
Income tax provision | 21.2 |
| | (38.5 | ) | | 40.6 |
| | (16.6 | ) | 58.3 |
| | 30.1 |
| | 100.2 |
| | 19.4 |
|
Impairment of crude oil and natural gas properties | (153.5 | ) | | (2.2 | ) | | (158.8 | ) | | (4.0 | ) | |
Impairment of properties and equipment | | (4.2 | ) | | (4.4 | ) | | (5.2 | ) | | (7.2 | ) |
Depreciation, depletion and amortization | (81.0 | ) | | (50.9 | ) | | (206.9 | ) | | (151.3 | ) | (107.0 | ) | | (70.1 | ) | | (204.4 | ) | | (125.9 | ) |
Accretion of asset retirement obligations | (1.6 | ) | | (0.9 | ) | | (4.7 | ) | | (2.6 | ) | (1.8 | ) | | (1.6 | ) | | (3.6 | ) | | (3.1 | ) |
Net income (loss) | $ | (41.5 | ) | | $ | 54.0 |
| | $ | (71.3 | ) | | $ | 23.7 |
| |
Net loss | | $ | (95.5 | ) | | $ | (46.9 | ) | | $ | (167.0 | ) | | $ | (29.8 | ) |
| | | | | | | | | | | | | | |
Adjusted EBITDA to net cash from operating activities: | | | | | | | | | | | | | | |
Adjusted EBITDA | $ | 128.6 |
| | $ | 62.6 |
| | $ | 311.6 |
| | $ | 201.8 |
| $ | 115.7 |
| | $ | 102.6 |
| | $ | 168.7 |
| | $ | 185.0 |
|
Interest expense, net | (10.7 | ) | | (12.4 | ) | | (31.8 | ) | | (37.9 | ) | (10.5 | ) | | (10.4 | ) | | (20.8 | ) | | (21.1 | ) |
Stock-based compensation | 4.8 |
| | 4.2 |
| | 14.3 |
| | 13.1 |
| 6.4 |
| | 5.1 |
| | 11.1 |
| | 9.5 |
|
Amortization of debt discount and issuance costs | 1.8 |
| | 1.8 |
| | 5.3 |
| | 5.2 |
| 1.3 |
| | 1.8 |
| | 3.1 |
| | 3.5 |
|
(Gain) loss on sale of properties and equipment | (0.1 | ) | | — |
| | (0.3 | ) | | 0.4 |
| 0.3 |
| | (0.2 | ) | | 0.2 |
| | (0.2 | ) |
Other | (1.7 | ) | | (0.7 | ) | | (5.5 | ) | | (2.4 | ) | (0.6 | ) | | (2.0 | ) | | 41.3 |
| | (5.9 | ) |
Changes in assets and liabilities | 13.8 |
| | 14.9 |
| | (10.6 | ) | | 21.8 |
| (16.0 | ) | | (32.3 | ) | | (5.8 | ) | | (24.3 | ) |
Net cash from operating activities | $ | 136.5 |
| | $ | 70.4 |
| | $ | 283.0 |
| | $ | 202.0 |
| $ | 96.6 |
| | $ | 64.6 |
| | $ | 197.8 |
| | $ | 146.5 |
|
Amounts above include resultsRegulatory Update
In May 2016, the EPA issued a draft Information Collection Request that will impact all known operators in the U.S. and which is aimed at regulating existing onshore oil and gas sources. The EPA also finalized a rule regarding source determination and permitting requirements for the onshore oil and gas industry under the Clean Air Act. Under this final rule, our operations could be subject to increased permitting costs and more stringent control requirements. In June 2016, the EPA published amendments to the 2012 NSPS OOOO rules focused on achieving additional methane and volatile organic compound reductions from continuingthe oil and discontinued operations.natural gas industry. The EPA also finalized pretreatment standards for the discharge of wastewater to publicly-owned treatment works for the onshore oil and gas extraction industry. Other agencies have also published new proposed or final rules impacting the onshore oil and gas industry. For example, the U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration issued an additional notice of proposed rulemaking in June 2016 related to the safety of transmission and gathering lines. In addition, in March 2016, the U.S. Fish and Wildlife Service finalized a rule to alter how it identifies critical habitat for endangered and threatened species, which could expand the reach of the Endangered Species Act depending on how it is implemented.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market-Sensitive Instruments and Risk Management
We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks.
Interest Rate Risk
Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 7.75% senior notes due 2022 and our Convertible Notes have a fixed ratesrate 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 SeptemberJune 30, 20152016, 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 SeptemberJune 30, 20152016 was $0.7$90.2 million with an averagea weighted-average interest rate of 0.1%0.3%. Based on a sensitivity analysis of our interest bearinginterest-bearing deposits as of SeptemberJune 30, 20152016, it was estimatedwe estimate that if marketa 1% increase in interest rates would have increased 1%, the impact onincrease interest income for the ninesix months ended SeptemberJune 30, 20152016 would have been insignificant.by approximately $0.5 million.
As of SeptemberJune 30, 20152016, excluding the $11.7 million irrevocable standby letter of credit, we had a $50.0 millionno outstanding balance on our revolving credit facility. It was estimated that if market interest rates would have increased or decreased 1%, our interest expense for the nine months ended September 30, 2015 would have changed by approximately $0.4 million.
Commodity Price Risk
We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our derivative policies and procedures are effective in achieving our risk management objectives.
The following table presents our derivative positions related to crude oil and natural gas sales in effect as of SeptemberJune 30, 20152016:
| | | | Collars | | Fixed-Price Swaps | | Basis Protection Swaps | | | | 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, 2015 (2) (in millions) | | 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 June 30, 2016 (2) (in millions) |
| | Floors | | Ceilings | | | | Floors | | Ceilings | |
Natural Gas | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
NYMEX | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2015 | | 2,830.0 |
| | $ | 3.92 |
| | $ | 4.30 |
| | 2,970.0 |
| | $ | 3.98 |
| | 4,800.0 |
| | $ | (0.29 | ) | | $ | 7.1 |
| |
2016 | | 7,820.0 |
| | 3.88 |
| | 4.24 |
| | 21,930.0 |
| | 3.93 |
| | 22,800.0 |
| | (0.30 | ) | | 31.5 |
| | 2,280.0 |
| | $ | 3.80 |
| | $ | 4.12 |
| | 15,410.0 |
| | $ | 3.66 |
| | 13,806.5 |
| | $ | (0.29 | ) | | $ | 10.6 |
|
2017 | | 7,920.0 |
| | 3.59 |
| | 4.13 |
| | 23,090.0 |
| | 3.67 |
| | 9,600.0 |
| | (0.29 | ) | | 20.7 |
| | 7,920.0 |
| | 3.59 |
| | 4.13 |
| | 27,290.0 |
| | 3.55 |
| | 12,000.0 |
| | (0.28 | ) | | 13.6 |
|
2018 | | 1,230.0 |
| | 3.00 |
| | 3.67 |
| | 4,830.0 |
| | 3.37 |
| | — |
| | — |
| | 1.7 |
| | 1,230.0 |
| | 3.00 |
| | 3.67 |
| | 17,430.0 |
| | 3.00 |
| | — |
| | — |
| | (0.1 | ) |
| | | | | | | | | | | | | | | | | |
CIG | | | | | | | | | | | | | | | | | |
2015 | | — |
| | — |
| | — |
| | 556.0 |
| | 4.02 |
| | — |
| | — |
| | 0.9 |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Natural Gas | | 19,800.0 |
| | | | | | 53,376.0 |
| | | | 37,200.0 |
| | | | 61.9 |
| | 11,430.0 |
| | | | | | 60,130.0 |
| | | | 25,806.5 |
| | | | 24.1 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Crude Oil | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
NYMEX | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2015 | | 234.0 |
| | 86.79 |
| | 96.63 |
| | 1,187.0 |
| | 89.42 |
| | — |
| | — |
| | 61.1 |
| |
2016 | | 1,740.0 |
| | 77.59 |
| | 97.55 |
| | 2,400.0 |
| | 90.37 |
| | — |
| | — |
| | 147.4 |
| | 870.0 |
| | 77.59 |
| | 97.55 |
| | 1,860.0 |
| | 72.21 |
| | — |
| | — |
| | 65.3 |
|
2017 | | 960.0 |
| | 54.06 |
| | 73.77 |
| | 180.0 |
| | 61.15 |
| | — |
| | — |
| | 7.8 |
| | 1,464.0 |
| | 49.22 |
| | 65.95 |
| | 3,004.0 |
| | 44.92 |
| | — |
| | — |
| | (17.4 | ) |
2018 | | | 1,512.0 |
| | 41.85 |
| | 54.31 |
| | 504.0 |
| | 47.08 |
| | — |
| | — |
| | (10.1 | ) |
| | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | |
Total Crude Oil | | 2,934.0 |
| | | | | | 3,767.0 |
| | | | — |
| | | | 216.3 |
| | 3,846.0 |
| | | | | | 5,368.0 |
| | | | — |
| | | | 37.8 |
|
Total Natural Gas and Crude Oil | | | | | | | | | | | | | | | | $ | 278.2 |
| | | | | | | | | | | | | | | | $ | 61.9 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
____________
| |
(1) | A standard unit of measurement for natural gas (one BBtu equals one MMcf). |
| |
(2) | Approximately 29.9%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 average NYMEX and CIG closing prices for crude oil and natural gas for the periods identified, as well as average sales prices we realized for our crude oil, natural gas and NGLs production:
| | | Three Months Ended | | Nine Months Ended | | Year Ended | Three Months Ended | | Six Months Ended | | Year Ended |
| September 30, 2015 | | September 30, 2015 | | December 31, 2014 | June 30, 2016 | | June 30, 2016 | | December 31, 2015 |
Average Index Closing Price: | | | | | | | | | | |
Crude oil (per Bbl) | | | | | | | | | | |
NYMEX | $ | 46.43 |
| | $ | 51.00 |
| | $ | 92.91 |
| $ | 45.59 |
| | $ | 39.52 |
| | $ | 48.80 |
|
Natural gas (per MMBtu) | | | | | | | | | | |
NYMEX | $ | 2.77 |
| | $ | 2.80 |
| | $ | 4.42 |
| $ | 1.95 |
| | $ | 2.02 |
| | $ | 2.66 |
|
CIG | 2.52 |
| | 2.54 |
| | 4.17 |
| 1.67 |
| | 1.73 |
| | 2.44 |
|
TETCO M-2 (1) | 1.21 |
| | 1.55 |
| | 3.35 |
| 1.27 |
| | 1.23 |
| | 1.49 |
|
| | | | | | | | | | |
Average Sales Price Realized: | | | | | | | | | | |
Excluding net settlements on derivatives | | | | | | | | | | |
Crude oil (per Bbl) | $ | 38.98 |
| | $ | 42.22 |
| | $ | 80.67 |
| $ | 40.37 |
| | $ | 34.46 |
| | $ | 40.14 |
|
Natural gas (per Mcf) | 2.05 |
| | 2.15 |
| | 3.87 |
| 1.37 |
| | 1.38 |
| | 2.04 |
|
NGLs (per Bbl) | 9.40 |
| | 10.45 |
| | 27.39 |
| 11.93 |
| | 9.89 |
| | 10.72 |
|
_____________
(1) TETCO M-2 is an index price upon which a majority of our natural gas produced in the Utica Shale is sold.
Based on a sensitivity analysis as of SeptemberJune 30, 20152016, it was estimatedwe estimate that a 10% increase in natural gas and crude oil prices, inclusive of basis, over the entire period for which we have derivatives in place, would have resulted in a decrease in the fair value of our derivative positions of $49.4$63.0 million, whereas a 10% decrease in prices would have resulted in an increase in fair value of $50.0$63.0 million.
See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to significant credit risk, we analyze the counterparties’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 Oil and Gas Exploration and Production segment's crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. Amounts due to our Gas Marketing segment are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions and end-users in various industries. As commoditynatural gas prices continue to remain depressed, certain customersthird-party producers under our Gas Marketing segment have begun and will continue to experience financial distress, which has led to certain contractual defaults. Todefaults and litigation; however, to date, we have had no material counterparty default losseslosses. We have initiated several legal actions for breach of contract, collection and related claims against certain third-party producers that are delinquent in their payment obligations, which have to date resulted in one default judgment. There have been no collections received to date and and some of the third-party producers have shut-in their wells and we expect this trend to continue for this segment.
A group of independent West Virginia natural gas producers has filed, but not served on RNG, a complaint 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 customers in either segment.pipelines owned and operated by Dominion and its affiliates. 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 derivative financial instruments. See Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for more detail on our derivative financial instruments.
Disclosure of Limitations
Because the information above included only those exposures that existed at SeptemberJune 30, 20152016, 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 SeptemberJune 30, 20152016, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the ChiefPrincipal 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 ChiefPrincipal Financial Officer concluded that our disclosure controls and procedures were effective as of SeptemberJune 30, 20152016.
Changes in Internal Control over Financial Reporting
During the three months ended SeptemberJune 30, 20152016, we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
PART II
ITEM 1. LEGAL PROCEEDINGS
Information regarding our legal proceedings can be found in Note 10, Commitments and Contingencies – Litigation, to our condensed consolidated financial statements included elsewhere in this report.
ITEM 1A. RISK FACTORS
We face many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described under Item 1A, Risk Factors, of our 20142015 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 2015 Form 10-K, except for the following:
Ballot initiatives have been proposed in Colorado that would impose draconian limitations on statewide oil and gas development activities or could result in vastly expanded authority of local governments to regulate or prohibit oil and natural gas production and development in their jurisdictions. Proponents of two such initiatives have submitted signatures in an effort to qualify the initiatives to appear on the ballot in November 2016. Either of these proposals could result in an effective ban on new development operations in areas where we have significant leasehold and existing production, and one of these proposals might affect production from existing wells. If either initiative is implemented and survives legal challenge, it would have a severe impact on our development plans and on our results of operations, financial condition and reserves. Future initiatives, legislation or regulations may be adopted with similar effects.
As previously disclosed, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state. Proponents of two such initiatives have submitted signatures in an effort to qualify the initiatives to appear on the ballot in November 2016. The signatures are subject to a verification process to be conducted by the Colorado Secretary of State. This process could take up to 30 days. We do not know what the outcome of this process will be. If approved by the voters of Colorado, the proposals will take effect by the end of 2016.
One of the initiatives, which we refer to as the “local control” initiative, would amend 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. If implemented, this amendment could result in our operations being subject to a variety of different, and possibly inconsistent, requirements in numerous different jurisdictions within the state of Colorado, and could prohibit exploration, development and production altogether in some or all of these jurisdictions. This would likely materially increase our costs and make our operations less efficient, and it could prevent us from developing and producing significant properties.
The other initiative, which we refer to as the “setback” initiative, would amend 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 “area of special concern,” broadly defined to include 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. The current minimum required setback between oil and gas wells and occupied structures is generally 500 feet. The Colorado Oil and Gas Conservation Commission has estimated that implementation of the
proposed initiative would make drilling unlawful on approximately 90% of the surface area of the state of Colorado, and approximately 85% of the surface area of Weld County. If passed, this proposal would effectively prohibit the vast majority of our planned future drilling activities, and would therefore make it impossible to continue to pursue our current development plans. This would have a highly material and adverse effect on our results of operations, financial condition and reserves.
Because substantially all of our current operations and reserves are located in Colorado, the risks we face with respect to these proposals, and possible similar future proposals, are greater than those of our competitors with more geographically diverse operations. We cannot predict the outcome of the potentially pending initiatives or possible future regulatory developments.
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, 2015 | | 15,237 |
| | $ | 51.36 |
|
August 1 - 31, 2015 | | 330 |
| | 46.95 |
|
September 1 - 30, 2015 | | — |
| | — |
|
Total third quarter purchases | | 15,567 |
| | 51.27 |
|
| | | | |
|
| | | | | | | |
Period | | Total Number of Shares Purchased (1) | | Average Price Paid per Share |
| | | | |
April 1 - 30, 2016 | | 41,911 |
| | $ | 59.59 |
|
May 1 - 31, 2016 | | — |
| | — |
|
June 1 - 30, 2016 | | 6,595 |
| | 57.61 |
|
Total second quarter purchases | | 48,506 |
| | 59.32 |
|
| | | | |
__________
| |
(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 |
| | | | | | | | | | | | |
10.1 | | Second Amendment to Third Amended and Restated Credit Agreement dated as of September 30, 2015, among PDC Energy, Inc. as the Borrower, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders. | | 8-K | | 001-37419
| | 10.1 | | 10/2/2015 | | |
| | | | | | | | | | | | |
10.2* | | Retirement Agreement with Gysle R. Shellum, Chief Financial Officer, dated October, 26, 2015. | | 8-K | | 000-07246 | | 10.1 | | 10/27/2015 | | |
| | | | | | | | | | | | |
31.1 | | Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | | | | | | | | | | X |
| | | | | | | | | | | | |
31.2 | | Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | | | | | | | | | | X |
| | | | | | | | | | | | |
32.1** | | Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. | | | | | | | | | | |
| | | | | | | | | | | | |
99.1 | | Certificate of Conversion, effective June 5, 2015. | | 8-K12B | | 000-07246 | | 99.1 | | 6/8/2015 | | |
| | | | | | | | | | | | |
99.2 | | Articles of Conversion, effective June 5, 2015. | | 8-K12B | | 000-07246 | | 99.2 | | 6/8/2015 | | |
| | | | | | | | | | | | |
101.INS | | XBRL Instance Document | | | | | | | | | | X |
| | | | | | | | | | | | |
101.SCH | | XBRL Taxonomy Extension Schema Document | | | | | | | | | | X |
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101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document | | | | | | | | | | X |
| | | | | | | | | | | | |
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. |
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| | | | Incorporated by Reference | | |
Exhibit Number | | Exhibit Description | | Form | | SEC File Number | | Exhibit | | Filing Date | | Filed Herewith |
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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 Principal 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 Principal Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. | | | | | | | | | | |
| | | | | | | | | | | | |
101.INS | | XBRL Instance Document | | | | | | | | | | X |
| | | | | | | | | | | | |
101.SCH | | XBRL Taxonomy Extension Schema Document | | | | | | | | | | X |
| | | | | | | | | | | | |
101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document | | | | | | | | | | X |
| | | | | | | | | | | | |
101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document | | | | | | | | | | X |
| | | | | | | | | | | | |
101.LAB | | XBRL Taxonomy Extension Label Linkbase Document | | | | | | | | | | X |
| | | | | | | | | | | | |
101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document | | | | | | | | | | X |
| | | | | | | | | | | | |
*Management contract or compensatory arrangement. |
** Furnished herewith. |
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 5, 2015August 9, 2016 | /s/ Barton R. Brookman |
| Barton R. Brookman |
| President and Chief Executive Officer |
| (principal executive officer) |
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| /s/ Gysle R. Shellum |
| Gysle R. Shellum |
| Chief Financial Officer |
| (principal financial officer) |
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| /s/ R. Scott Meyers |
| R. Scott Meyers |
| Chief Accounting Officer |
| (principal accountingfinancial officer) |
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