Delaware | 95-2636730 |
(State of incorporation) | (I.R.S. Employer Identification No.) |
Large accelerated filer x | Accelerated filer o |
Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Emerging growth company o |
PART I – FINANCIAL INFORMATION | Page | ||
Item 1. | Financial Statements | ||
Item 2. | |||
Item 3. | |||
Item 4. | |||
PART II – OTHER INFORMATION | |||
Item 1. | |||
Item 1A. | |||
Item 2. | |||
Item 3. | |||
Item 4. | |||
Item 5. | |||
Item 6. | |||
• | changes in worldwide production volumes and demand, including economic conditions that might impact demand and prices for the products we produce; |
• | volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices; |
• | volatility and widening of differentials; |
• | 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 of those laws and regulations, liabilities arising thereunder, and the costs to comply with those laws and regulations; |
• | declines in the value of our crude oil, natural gas, and NGLs properties resulting in impairments; |
• | changes in estimates of proved reserves; |
• | inaccuracy of reserve estimates and expected production rates; |
• | potential for production decline rates from our wells being greater than expected; |
• | timing and extent of our success in discovering, acquiring, developing, and producing reserves; |
• | availability of sufficient pipeline, gathering, and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production; |
• | timing and receipt of necessary regulatory permits; |
• | risks incidental to the drilling and operation of crude oil and natural gas wells; |
• | difficulties in integrating our operations as a result of any significant acquisitions and acreage exchanges; |
• | increases or changes in expenses; |
• | availability of supplies, materials, contractors, and services that may delay the drilling or completion of our wells; |
• | potential losses of acreage due to lease expirations or otherwise; |
• | increases or adverse changes in construction costs and procurement costs associated with future build out of midstream-related assets; |
• | future cash flows, liquidity, and financial condition; |
• | competition within the oil and gas industry; |
• | availability and cost of capital; |
• | our success in marketing crude oil, natural gas, and NGLs; |
• | effect of crude oil and natural gas derivatives activities; |
• | impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events; |
• | cost of pending or future litigation; |
• | effect that acquisitions we may pursue have on our capital requirements; |
• | our ability to retain or attract senior management and key technical employees; and |
• | success of strategic plans, expectations, and objectives for our future operations. |
March 31, 2018 | December 31, 2017 | |||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 45,923 | $ | 180,675 | ||||
Accounts receivable, net | 181,025 | 197,598 | ||||||
Fair value of derivatives | 28,610 | 14,338 | ||||||
Prepaid expenses and other current assets | 8,897 | 8,613 | ||||||
Total current assets | 264,455 | 401,224 | ||||||
Properties and equipment, net | 4,231,257 | 3,933,467 | ||||||
Assets held-for-sale, net | 1,647 | 40,084 | ||||||
Other assets | 24,798 | 45,116 | ||||||
Total Assets | $ | 4,522,157 | $ | 4,419,891 | ||||
Liabilities and Stockholders' Equity | ||||||||
Liabilities | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 195,703 | $ | 150,067 | ||||
Production tax liability | 36,650 | 37,654 | ||||||
Fair value of derivatives | 110,683 | 79,302 | ||||||
Funds held for distribution | 97,611 | 95,811 | ||||||
Accrued interest payable | 13,760 | 11,815 | ||||||
Other accrued expenses | 33,777 | 42,987 | ||||||
Total current liabilities | 488,184 | 417,636 | ||||||
Long-term debt | 1,154,528 | 1,151,932 | ||||||
Deferred income taxes | 187,183 | 191,992 | ||||||
Asset retirement obligations | 73,905 | 71,006 | ||||||
Fair value of derivatives | 26,426 | 22,343 | ||||||
Other liabilities | 94,557 | 57,333 | ||||||
Total liabilities | 2,024,783 | 1,912,242 | ||||||
Commitments and contingent liabilities | ||||||||
Stockholders' equity | ||||||||
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,999,010 and 65,955,080 issued as of March 31, 2018 and December 31, 2017, respectively | 660 | 659 | ||||||
Additional paid-in capital | 2,504,663 | 2,503,294 | ||||||
Retained earnings (deficit) | (6,435 | ) | 6,704 | |||||
Treasury shares - at cost, 29,255 and 55,927 as of March 31, 2018 and December 31, 2017, respectively | (1,514 | ) | (3,008 | ) | ||||
Total stockholders' equity | 2,497,374 | 2,507,649 | ||||||
Total Liabilities and Stockholders' Equity | $ | 4,522,157 | $ | 4,419,891 |
Three Months Ended March 31, | ||||||||
2018 | 2017 | |||||||
Revenues | ||||||||
Crude oil, natural gas, and NGLs sales | $ | 305,225 | $ | 189,692 | ||||
Commodity price risk management gain (loss), net | (47,240 | ) | 80,704 | |||||
Other income | 2,615 | 3,311 | ||||||
Total revenues | 260,600 | 273,707 | ||||||
Costs, expenses and other | ||||||||
Lease operating expenses | 29,636 | 19,789 | ||||||
Production taxes | 20,169 | 12,399 | ||||||
Transportation, gathering, and processing expenses | 7,313 | 5,902 | ||||||
Exploration, geologic, and geophysical expense | 2,646 | 954 | ||||||
Impairment of properties and equipment | 33,188 | 2,193 | ||||||
General and administrative expense | 35,696 | 26,315 | ||||||
Depreciation, depletion, and amortization | 126,788 | 109,316 | ||||||
Accretion of asset retirement obligations | 1,288 | 1,768 | ||||||
(Gain) loss on sale of properties and equipment | 1,432 | (160 | ) | |||||
Other expenses | 2,768 | 3,528 | ||||||
Total costs, expenses and other | 260,924 | 182,004 | ||||||
Income (loss) from operations | (324 | ) | 91,703 | |||||
Interest expense | (17,529 | ) | (19,467 | ) | ||||
Interest income | 148 | 240 | ||||||
Income (loss) before income taxes | (17,705 | ) | 72,476 | |||||
Income tax (expense) benefit | 4,566 | (26,330 | ) | |||||
Net income (loss) | $ | (13,139 | ) | $ | 46,146 | |||
Earnings per share: | ||||||||
Basic | $ | (0.20 | ) | $ | 0.70 | |||
Diluted | $ | (0.20 | ) | $ | 0.70 | |||
Weighted-average common shares outstanding: | ||||||||
Basic | 65,957 | 65,749 | ||||||
Diluted | 65,957 | 66,117 | ||||||
Three Months Ended March 31, | ||||||||
2018 | 2017 | |||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | $ | (13,139 | ) | $ | 46,146 | |||
Adjustments to net income (loss) to reconcile to net cash from operating activities: | ||||||||
Net change in fair value of unsettled commodity derivatives | 21,202 | (80,153 | ) | |||||
Depreciation, depletion and amortization | 126,788 | 109,316 | ||||||
Impairment of properties and equipment | 33,188 | 2,193 | ||||||
Accretion of asset retirement obligations | 1,288 | 1,768 | ||||||
Non-cash stock-based compensation | 5,261 | 4,454 | ||||||
(Gain) loss on sale of properties and equipment | 1,432 | (160 | ) | |||||
Amortization of debt discount and issuance costs | 3,246 | 3,184 | ||||||
Deferred income taxes | (4,809 | ) | 26,280 | |||||
Other | 515 | 722 | ||||||
Changes in assets and liabilities | 30,177 | 25,750 | ||||||
Net cash from operating activities | 205,149 | 139,500 | ||||||
Cash flows from investing activities: | ||||||||
Capital expenditures for development of crude oil and natural gas properties | (196,917 | ) | (129,826 | ) | ||||
Capital expenditures for other properties and equipment | (1,066 | ) | (821 | ) | ||||
Acquisition of crude oil and natural gas properties, including settlement adjustments | (180,825 | ) | 6,181 | |||||
Proceeds from sale of properties and equipment | 20 | 737 | ||||||
Proceeds from divestiture | 39,023 | — | ||||||
Restricted cash | 1,249 | — | ||||||
Purchase of short-term investments | — | (49,890 | ) | |||||
Net cash from investing activities | (338,516 | ) | (173,619 | ) | ||||
Cash flows from financing activities: | ||||||||
Proceeds from revolving credit facility | 35,000 | — | ||||||
Repayment of revolving credit facility | (35,000 | ) | — | |||||
Purchase of treasury stock | (2,255 | ) | (2,017 | ) | ||||
Other | (379 | ) | (340 | ) | ||||
Net cash from financing activities | (2,634 | ) | (2,357 | ) | ||||
Net change in cash, cash equivalents, and restricted cash | (136,001 | ) | (36,476 | ) | ||||
Cash, cash equivalents, and restricted cash, beginning of period | 189,925 | 244,100 | ||||||
Cash, cash equivalents, and restricted cash, end of period | $ | 53,924 | $ | 207,624 | ||||
Supplemental cash flow information: | ||||||||
Cash payments (receipts) for: | ||||||||
Interest, net of capitalized interest | $ | 12,343 | $ | 13,224 | ||||
Income taxes | 193 | (39 | ) | |||||
Non-cash investing and financing activities: | ||||||||
Change in accounts payable related to capital expenditures | $ | 51,093 | $ | 69,604 | ||||
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals | 5,354 | 1,233 | ||||||
Purchase of properties and equipment under capital leases | 348 | 1,190 |
Common Stock | Treasury Stock | ||||||||||||||||||||||||
Shares | Amount | Additional Paid-in Capital | Shares | Amount | Retained Earnings (Deficit) | Total Stockholders' Equity | |||||||||||||||||||
Balance, December 31, 2017 | 65,955,080 | $ | 659 | $ | 2,503,294 | (55,927 | ) | $ | (3,008 | ) | $ | 6,704 | $ | 2,507,649 | |||||||||||
Net loss | — | — | — | — | — | (13,139 | ) | (13,139 | ) | ||||||||||||||||
Purchase of treasury shares | — | — | — | (41,357 | ) | (2,255 | ) | — | (2,255 | ) | |||||||||||||||
Issuance of treasury shares | — | — | (3,891 | ) | 70,603 | 3,891 | — | — | |||||||||||||||||
Non-employee directors' deferred compensation plan | — | — | — | (2,574 | ) | (142 | ) | — | (142 | ) | |||||||||||||||
Issuance of stock awards, net of forfeitures | 43,930 | 1 | (1 | ) | — | — | — | — | |||||||||||||||||
Stock-based compensation expense | — | — | 5,261 | — | — | — | 5,261 | ||||||||||||||||||
Other | — | — | — | — | — | — | — | ||||||||||||||||||
Balance, March 31, 2018 | 65,999,010 | $ | 660 | $ | 2,504,663 | (29,255 | ) | $ | (1,514 | ) | $ | (6,435 | ) | $ | 2,497,374 |
March 31, 2018 | December 31, 2017 | ||||||
(in thousands) | |||||||
Cash and cash equivalents | $ | 45,923 | $ | 180,675 | |||
Restricted cash | 8,001 | 9,250 | |||||
Cash, cash equivalents, and restricted cash shown in the condensed consolidated statements of cash flows | $ | 53,924 | $ | 189,925 |
March 31, 2018 | |||
Acquisition costs: | |||
Cash | $ | 171,091 | |
Deposit made in prior period | 21,000 | ||
Total cash consideration | 192,091 | ||
Other purchase price adjustments | 9,734 | ||
Total acquisition costs | $ | 201,825 | |
Recognized amounts of identifiable assets acquired and liabilities assumed: | |||
Assets acquired: | |||
Current assets | $ | 517 | |
Crude oil and natural gas properties - proved | 208,279 | ||
Other assets | 2,796 | ||
Total assets acquired | 211,592 | ||
Liabilities assumed: | |||
Current liabilities | (5,080 | ) | |
Asset retirement obligations | (4,687 | ) | |
Total liabilities assumed | (9,767 | ) | |
Total identifiable net assets acquired | $ | 201,825 |
Three Months Ended March 31, | |||||||||||
Revenue by Commodity and Operating Region | 2018 | 2017 (2) | Percentage Change | ||||||||
Crude oil | |||||||||||
Wattenberg Field | $ | 170,306 | $ | 105,188 | 61.9 | % | |||||
Delaware Basin | 53,418 | 13,538 | 294.6 | % | |||||||
Utica Shale (1) | 2,696 | 4,270 | (36.9 | )% | |||||||
Total | $ | 226,420 | $ | 122,996 | 84.1 | % | |||||
Natural gas | |||||||||||
Wattenberg Field | $ | 29,772 | $ | 32,614 | (8.7 | )% | |||||
Delaware Basin | 7,679 | 2,468 | 211.1 | % | |||||||
Utica Shale (1) | 1,110 | 1,860 | (40.3 | )% | |||||||
Total | $ | 38,561 | $ | 36,942 | 4.4 | % | |||||
NGLs | |||||||||||
Wattenberg Field | $ | 28,770 | $ | 25,318 | 13.6 | % | |||||
Delaware Basin | 10,635 | 2,947 | 260.9 | % | |||||||
Utica Shale (1) | 839 | 1,489 | (43.7 | )% | |||||||
Total | $ | 40,244 | $ | 29,754 | 35.3 | % | |||||
Revenue by Operating Region | |||||||||||
Wattenberg Field | $ | 228,848 | $ | 163,120 | 40.3 | % | |||||
Delaware Basin | 71,732 | 18,953 | 278.5 | % | |||||||
Utica Shale (1) | 4,645 | 7,619 | (39.0 | )% | |||||||
Total | $ | 305,225 | $ | 189,692 | 60.9 | % |
Amount | |||
(in thousands) | |||
Beginning balance, January 1, 2018 | $ | 4,446 | |
Contract assets amortized as a reduction to crude oil, natural gas, and NGLs sales | (1,233 | ) | |
Ending balance, March 31, 2018 | $ | 3,213 |
March 31, 2018 | December 31, 2017 | ||||||||||||||||||||||
Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
Assets: | |||||||||||||||||||||||
Total assets | $ | 22,467 | $ | 6,143 | $ | 28,610 | $ | 12,949 | $ | 1,389 | $ | 14,338 | |||||||||||
Total liabilities | 122,133 | 14,976 | 137,109 | 90,569 | 11,076 | 101,645 | |||||||||||||||||
Net liability | $ | (99,666 | ) | $ | (8,833 | ) | $ | (108,499 | ) | $ | (77,620 | ) | $ | (9,687 | ) | $ | (87,307 | ) | |||||
Three Months Ended March 31, | ||||||||
2018 | 2017 | |||||||
(in thousands) | ||||||||
Fair value of Level 3 instruments, net liability beginning of period | $ | (9,687 | ) | $ | (9,574 | ) | ||
Changes in fair value included in condensed consolidated statement of operations line item: | ||||||||
Commodity price risk management gain (loss), net | (2,152 | ) | 13,360 | |||||
Settlements included in condensed consolidated statement of operations line items: | ||||||||
Commodity price risk management gain (loss), net | 3,006 | (1,470 | ) | |||||
Fair value of Level 3 instruments, net asset (liability) end of period | $ | (8,833 | ) | $ | 2,316 | |||
Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item: | ||||||||
Commodity price risk management gain (loss), net | $ | 1,205 | $ | 11,427 | ||||
Estimated Fair Value | Percent of Par | ||||||
(in millions) | |||||||
Senior notes: | |||||||
2021 Convertible Notes | $ | 194.0 | 97.0 | % | |||
2024 Senior Notes | 409.0 | 102.3 | % | ||||
2026 Senior Notes | 593.3 | 98.9 | % |
Collars | Fixed-Price Swaps | |||||||||||||||||||||
Commodity/ Index/ Maturity Period | Quantity (Gas - BBtu Oil - MBbls) | Weighted-Average Contract Price | Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls) | Weighted- Average Contract Price | Fair Value March 31, 2018 (1) (in millions) | |||||||||||||||||
Floors | Ceilings | |||||||||||||||||||||
Crude Oil | ||||||||||||||||||||||
NYMEX | ||||||||||||||||||||||
2018 | 1,784.0 | $ | 46.64 | $ | 57.53 | 7,704.0 | $ | 52.54 | $ | (91.4 | ) | |||||||||||
2019 | 400.0 | 50.00 | 60.67 | 7,800.0 | 53.20 | (42.9 | ) | |||||||||||||||
Total Crude Oil | 2,184.0 | 15,504.0 | $ | (134.3 | ) | |||||||||||||||||
Natural Gas | ||||||||||||||||||||||
NYMEX | ||||||||||||||||||||||
2018 | 2,735.0 | $ | 3.00 | $ | 3.56 | 40,335.0 | $ | 2.94 | $ | 5.1 | ||||||||||||
2019 | — | — | — | 4,004.0 | 2.77 | (0.1 | ) | |||||||||||||||
Total Natural Gas | 2,735.0 | 44,339.0 | $ | 5.0 | ||||||||||||||||||
Basis Protection - Crude Oil | ||||||||||||||||||||||
Midland Cushing | ||||||||||||||||||||||
2018 | — | $ | — | $ | — | 1,456.1 | $ | (0.10 | ) | $ | 5.4 | |||||||||||
Total Basis Protection - Crude Oil | — | 1,456.1 | $ | 5.4 | ||||||||||||||||||
Basis Protection - Natural Gas | ||||||||||||||||||||||
CIG | ||||||||||||||||||||||
2018 | — | $ | — | $ | — | 31,409.9 | $ | (0.43 | ) | $ | 12.3 | |||||||||||
2019 | — | — | — | 4,004.0 | (0.88 | ) | (0.1 | ) | ||||||||||||||
Waha | ||||||||||||||||||||||
2018 | — | — | — | 4,923.8 | (0.50 | ) | 3.4 | |||||||||||||||
El Paso | ||||||||||||||||||||||
2018 | — | — | — | 2,450.0 | (0.62 | ) | 1.6 | |||||||||||||||
Total Basis Protection - Natural Gas | — | 42,787.7 | $ | 17.2 | ||||||||||||||||||
Propane | ||||||||||||||||||||||
Mont Belvieu | ||||||||||||||||||||||
2018 | — | $ | — | $ | — | 714.4 | $ | 32.52 | $ | — | ||||||||||||
Total Propane | — | 714.4 | $ | — | ||||||||||||||||||
Rollfactor (2) | ||||||||||||||||||||||
Crude Oil CMA | ||||||||||||||||||||||
2018 | — | $ | — | $ | — | 4,192 | $ | 0.12 | $ | (1.8 | ) | |||||||||||
Total Rollfactor | — | 4,192 | $ | (1.8 | ) | |||||||||||||||||
Commodity Derivatives Fair Value | $ | (108.5 | ) |
(1) | Approximately 21.5 percent of the fair value of our commodity derivative assets and 10.9 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). |
(2) | These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month. |
Fair Value | |||||||||||
Derivative instruments: | Condensed consolidated balance sheet line item | March 31, 2018 | December 31, 2017 | ||||||||
(in thousands) | |||||||||||
Derivative assets: | Current | ||||||||||
Commodity derivative contracts | Fair value of derivatives | $ | 5,958 | $ | 7,340 | ||||||
Basis protection derivative contracts | Fair value of derivatives | 22,652 | 6,998 | ||||||||
28,610 | 14,338 | ||||||||||
Non-current | — | — | |||||||||
Total derivative assets | $ | 28,610 | $ | 14,338 | |||||||
Derivative liabilities: | Current | ||||||||||
Commodity derivative contracts | Fair value of derivatives | 108,763 | 77,999 | ||||||||
Basis protection derivative contracts | Fair value of derivatives | 122 | 234 | ||||||||
Rollfactor derivative contracts | Fair value of derivatives | 1,798 | 1,069 | ||||||||
110,683 | 79,302 | ||||||||||
Non-current | |||||||||||
Commodity derivative contracts | Fair value of derivatives | 26,447 | 22,343 | ||||||||
Basis protection derivative contracts | Fair value of derivatives | (21 | ) | — | |||||||
26,426 | 22,343 | ||||||||||
Total derivative liabilities | $ | 137,109 | $ | 101,645 |
Three Months Ended March 31, | ||||||||
Condensed consolidated statement of operations line item | 2018 | 2017 | ||||||
(in thousands) | ||||||||
Commodity price risk management gain (loss), net | ||||||||
Net settlements | $ | (26,038 | ) | $ | 551 | |||
Net change in fair value of unsettled derivatives | (21,202 | ) | 80,153 | |||||
Total commodity price risk management gain (loss), net | $ | (47,240 | ) | $ | 80,704 | |||
As of March 31, 2018 | Derivative instruments, recorded in condensed consolidated balance sheet, gross | Effect of master netting agreements | Derivative instruments, net | |||||||||
(in thousands) | ||||||||||||
Asset derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 28,610 | $ | (27,971 | ) | $ | 639 | |||||
Liability derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 137,109 | $ | (27,971 | ) | $ | 109,138 | |||||
As of December 31, 2017 | Derivative instruments, recorded in condensed consolidated balance sheet, gross | Effect of master netting agreements | Derivative instruments, net | |||||||||
(in thousands) | ||||||||||||
Asset derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 14,338 | $ | (14,173 | ) | $ | 165 | |||||
Liability derivatives: | ||||||||||||
Derivative instruments, at fair value | $ | 101,645 | $ | (14,173 | ) | $ | 87,472 | |||||
March 31, 2018 | December 31, 2017 | ||||||
(in thousands) | |||||||
Properties and equipment, net: | |||||||
Crude oil and natural gas properties | |||||||
Proved | $ | 4,706,258 | $ | 4,356,922 | |||
Unproved | 1,055,774 | 1,097,317 | |||||
Total crude oil and natural gas properties | 5,762,032 | 5,454,239 | |||||
Infrastructure, pipeline, and other | 125,529 | 109,359 | |||||
Land and buildings | 12,679 | 10,960 | |||||
Construction in progress | 294,311 | 196,024 | |||||
Properties and equipment, at cost | 6,194,551 | 5,770,582 | |||||
Accumulated DD&A | (1,963,294 | ) | (1,837,115 | ) | |||
Properties and equipment, net | $ | 4,231,257 | $ | 3,933,467 | |||
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(in thousands) | |||||||
Impairment of proved and unproved properties | $ | 33,130 | $ | 2,102 | |||
Amortization of individually insignificant unproved properties | 58 | 91 | |||||
Impairment of crude oil and natural gas properties | $ | 33,188 | $ | 2,193 |
March 31, 2018 | December 31, 2017 | ||||||
(in thousands) | |||||||
Assets | |||||||
Properties and equipment, net | $ | 1,647 | $ | 40,583 | |||
Total assets | $ | 1,647 | $ | 40,583 | |||
Liabilities | |||||||
Asset retirement obligation | $ | — | $ | 499 | |||
Total liabilities | $ | — | $ | 499 | |||
Assets held-for-sale, net | $ | 1,647 | $ | 40,084 |
March 31, 2018 | December 31, 2017 | ||||||
(in thousands, except for number of wells) | |||||||
Beginning balance | $ | 15,448 | $ | — | |||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 17,143 | 51,776 | |||||
Reclassifications to proved properties | — | (36,328 | ) | ||||
Ending balance | $ | 32,591 | $ | 15,448 | |||
Number of wells pending determination at period end | 3 | 3 |
March 31, 2018 | December 31, 2017 | |||||||
(in thousands) | ||||||||
Employee benefits | $ | 10,901 | $ | 22,383 | ||||
Asset retirement obligations | 15,944 | 15,801 | ||||||
Environmental expenses | 2,074 | 1,374 | ||||||
Short-term deferred oil gathering credit | 2,010 | — | ||||||
Other | 2,848 | 3,429 | ||||||
Other accrued expenses | $ | 33,777 | $ | 42,987 | ||||
March 31, 2018 | December 31, 2017 | |||||||
(in thousands) | ||||||||
Production taxes | $ | 63,454 | $ | 50,476 | ||||
Long-term deferred oil gathering credit | 21,608 | — | ||||||
Other | 9,495 | 6,857 | ||||||
Other liabilities | $ | 94,557 | $ | 57,333 | ||||
March 31, 2018 | December 31, 2017 | ||||||
(in thousands) | |||||||
Senior notes: | |||||||
1.125% Convertible Notes due 2021: | |||||||
Principal amount | $ | 200,000 | $ | 200,000 | |||
Unamortized discount | (28,478 | ) | (30,328 | ) | |||
Unamortized debt issuance costs | (3,371 | ) | (3,615 | ) | |||
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs | 168,151 | 166,057 | |||||
5.75% Senior Notes due 2026: | |||||||
Principal amount | 600,000 | 600,000 | |||||
Unamortized debt issuance costs | (7,298 | ) | (7,555 | ) | |||
5.75% Senior Notes due 2026, net of unamortized debt issuance costs | 592,702 | 592,445 | |||||
6.125% Senior Notes due 2024: | |||||||
Principal amount | 400,000 | 400,000 | |||||
Unamortized debt issuance costs | (6,325 | ) | (6,570 | ) | |||
6.125% Senior Notes due 2024, net of unamortized debt issuance costs | 393,675 | 393,430 | |||||
Total senior notes | 1,154,528 | 1,151,932 | |||||
Revolving credit facility | — | — | |||||
Total long-term debt, net of unamortized discount and debt issuance costs | $ | 1,154,528 | $ | 1,151,932 |
March 31, 2018 | December 31, 2017 | |||||||
(in thousands) | ||||||||
Vehicles | $ | 6,500 | $ | 6,249 | ||||
Accumulated depreciation | (2,271 | ) | (1,882 | ) | ||||
$ | 4,229 | $ | 4,367 |
For the Twelve Months Ending March 31, | Amount | |||
(in thousands) | ||||
2019 | $ | 1,952 | ||
2020 | 2,061 | |||
2021 | 1,247 | |||
5,260 | ||||
Less executory cost | (400 | ) | ||
Less amount representing interest | (501 | ) | ||
Present value of minimum lease payments | $ | 4,359 | ||
Short-term capital lease obligations | $ | 1,789 | ||
Long-term capital lease obligations | 2,570 | |||
$ | 4,359 |
Amount | |||
(in thousands) | |||
Balance at December 31, 2017 | $ | 87,306 | |
Obligations incurred with development activities | 620 | ||
Obligations incurred with acquisition | 4,687 | ||
Accretion expense | 1,288 | ||
Revisions in estimated cash flows | 50 | ||
Obligations discharged with asset retirements and divestiture | (4,102 | ) | |
Balance at March 31, 2018 | 89,849 | ||
Less current portion | (15,944 | ) | |
Long-term portion | $ | 73,905 | |
For the Twelve Months Ending March 31, | ||||||||||||||||||||||||||
Area | 2019 | 2020 | 2021 | 2022 | 2023 and Through Expiration | Total | Expiration Date | |||||||||||||||||||
Natural gas (MMcf) | ||||||||||||||||||||||||||
Wattenberg Field | 7,416 | 27,794 | 31,025 | 31,025 | 114,272 | 211,532 | April 30, 2026 | |||||||||||||||||||
Delaware Basin | 25,520 | 25,600 | 11,000 | — | — | 62,120 | December 31, 2020 | |||||||||||||||||||
Gas Marketing | 7,117 | 7,136 | 7,117 | 6,965 | 2,830 | 31,165 | August 31, 2022 | |||||||||||||||||||
Total | 40,053 | 60,530 | 49,142 | 37,990 | 117,102 | 304,817 | ||||||||||||||||||||
Crude oil (MBbls) | ||||||||||||||||||||||||||
Wattenberg Field | 7,438 | 8,062 | 5,085 | 4,563 | 4,937 | 30,085 | April 30, 2023 | |||||||||||||||||||
Delaware Basin | 4,493 | 8,227 | 8,580 | 7,392 | 14,080 | 42,772 | December 31, 2023 | |||||||||||||||||||
Total | 11,931 | 16,289 | 13,665 | 11,955 | 19,017 | 72,857 | ||||||||||||||||||||
Dollar commitment (in thousands) | $ | 64,690 | $ | 99,560 | $ | 69,434 | $ | 65,060 | $ | 160,183 | $ | 458,927 |
Three Months Ended March 31, | ||||||||
2018 | 2017 | |||||||
(in thousands) | ||||||||
Stock-based compensation expense | $ | 5,261 | $ | 4,453 | ||||
Income tax benefit | (1,261 | ) | (1,666 | ) | ||||
Net stock-based compensation expense | $ | 4,000 | $ | 2,787 | ||||
Shares | Weighted-Average Grant Date Fair Value per Share | |||||
Non-vested at December 31, 2017 | 472,132 | $ | 60.23 | |||
Granted | 136,256 | 50.94 | ||||
Vested | (66,253 | ) | 58.16 | |||
Forfeited | (5,800 | ) | 68.18 | |||
Non-vested at March 31, 2018 | 536,335 | 58.04 | ||||
As of/Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(in thousands, except per share data) | |||||||
Total intrinsic value of time-based awards vested | $ | 3,530 | $ | 3,602 | |||
Total intrinsic value of time-based awards non-vested | 26,297 | 33,366 | |||||
Market price per share as of March 31, | 49.03 | 62.35 | |||||
Weighted-average grant date fair value per share | 50.94 | 73.28 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
Expected term of award (in years) | 3 | 3 | |||||
Risk-free interest rate | 2.4 | % | 1.4 | % | |||
Expected volatility | 42.3 | % | 51.4 | % | |||
Weighted-average grant date fair value per share | $ | 69.98 | $ | 94.02 |
Shares | Weighted-Average Grant Date Fair Value per Share | ||||||
Non-vested at December 31, 2017 | 52,349 | $ | 84.06 | ||||
Granted | 90,778 | 69.98 | |||||
Forfeited | (4,128 | ) | 94.02 | ||||
Non-vested at March 31, 2018 | 138,999 | 74.57 | |||||
As of Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(in thousands, except per share data) | |||||||
Total intrinsic value of market-based awards non-vested | $ | 6,815 | $ | 4,769 | |||
Market price per common share as of March 31, | 49.03 | 62.35 | |||||
Weighted-average grant date fair value per share | 69.98 | 94.02 |
Three Months Ended March 31, | |||||
2018 | 2017 | ||||
(in thousands) | |||||
Weighted-average common shares outstanding - basic | 65,957 | 65,749 | |||
Dilutive effect of: | |||||
Restricted stock | — | 211 | |||
Convertible notes | — | 157 | |||
Weighted-average common shares and equivalents outstanding - diluted | 65,957 | 66,117 |
Three Months Ended March 31, | |||||
2018 | 2017 | ||||
(in thousands) | |||||
Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: | |||||
Restricted stock | 491 | 76 | |||
Convertible notes | — | — | |||
Other equity-based awards | 198 | 18 | |||
Total anti-dilutive common share equivalents | 689 | 94 | |||
(i) | PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; |
(ii) | PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes; |
(iii) | Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor, and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and |
(iv) | Parent and subsidiaries on a consolidated basis ("Consolidated"). |
Condensed Consolidating Balance Sheets | ||||||||||||||||
March 31, 2018 | ||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | |||||||||||||
(in thousands) | ||||||||||||||||
Current assets: | ||||||||||||||||
Cash and cash equivalents | $ | 45,923 | $ | — | $ | — | $ | 45,923 | ||||||||
Accounts receivable, net | 143,250 | 37,775 | — | 181,025 | ||||||||||||
Fair value of derivatives | 28,610 | — | — | 28,610 | ||||||||||||
Prepaid expenses and other current assets | 7,116 | 1,781 | — | 8,897 | ||||||||||||
Total current assets | 224,899 | 39,556 | — | 264,455 | ||||||||||||
Properties and equipment, net | 2,139,471 | 2,091,786 | — | 4,231,257 | ||||||||||||
Assets held-for-sale, net | 1,647 | — | — | 1,647 | ||||||||||||
Intercompany receivable | 294,476 | — | (294,476 | ) | — | |||||||||||
Investment in subsidiaries | 1,605,330 | — | (1,605,330 | ) | — | |||||||||||
Other assets | 23,339 | 1,459 | — | 24,798 | ||||||||||||
Total Assets | $ | 4,289,162 | $ | 2,132,801 | $ | (1,899,806 | ) | $ | 4,522,157 | |||||||
Liabilities and Stockholders' Equity | ||||||||||||||||
Liabilities | ||||||||||||||||
Current liabilities: | ||||||||||||||||
Accounts payable | $ | 113,529 | $ | 82,174 | $ | — | $ | 195,703 | ||||||||
Production tax liability | 35,309 | 1,341 | — | 36,650 | ||||||||||||
Fair value of derivatives | 110,683 | — | — | 110,683 | ||||||||||||
Funds held for distribution | 80,203 | 17,408 | — | 97,611 | ||||||||||||
Accrued interest payable | 13,756 | 4 | — | 13,760 | ||||||||||||
Other accrued expenses | 33,136 | 641 | — | 33,777 | ||||||||||||
Total current liabilities | 386,616 | 101,568 | — | 488,184 | ||||||||||||
Intercompany payable | — | 294,476 | (294,476 | ) | — | |||||||||||
Long-term debt | 1,154,528 | — | — | 1,154,528 | ||||||||||||
Deferred income taxes | 62,088 | 125,095 | — | 187,183 | ||||||||||||
Asset retirement obligations | 67,922 | 5,983 | — | 73,905 | ||||||||||||
Fair value of derivatives | 26,426 | — | — | 26,426 | ||||||||||||
Other liabilities | 94,208 | 349 | — | 94,557 | ||||||||||||
Total liabilities | 1,791,788 | 527,471 | (294,476 | ) | 2,024,783 | |||||||||||
Commitments and contingent liabilities | ||||||||||||||||
Stockholders' Equity | ||||||||||||||||
Stockholders' equity | ||||||||||||||||
Common shares | 660 | — | — | 660 | ||||||||||||
Additional paid-in capital | 2,504,663 | 1,766,777 | (1,766,777 | ) | 2,504,663 | |||||||||||
Retained earnings | (6,435 | ) | (161,447 | ) | 161,447 | (6,435 | ) | |||||||||
Treasury shares | (1,514 | ) | — | — | (1,514 | ) | ||||||||||
Total stockholders' equity | 2,497,374 | 1,605,330 | (1,605,330 | ) | 2,497,374 | |||||||||||
Total Liabilities and Stockholders' Equity | $ | 4,289,162 | $ | 2,132,801 | $ | (1,899,806 | ) | $ | 4,522,157 |
Condensed Consolidating Balance Sheets | ||||||||||||||||
December 31, 2017 | ||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | |||||||||||||
(in thousands) | ||||||||||||||||
Current assets: | ||||||||||||||||
Cash and cash equivalents | $ | 180,675 | $ | — | $ | — | $ | 180,675 | ||||||||
Accounts receivable, net | 160,490 | 37,108 | — | 197,598 | ||||||||||||
Fair value of derivatives | 14,338 | — | — | 14,338 | ||||||||||||
Prepaid expenses and other current assets | 8,284 | 329 | — | 8,613 | ||||||||||||
Total current assets | 363,787 | 37,437 | — | 401,224 | ||||||||||||
Properties and equipment, net | 1,891,314 | 2,042,153 | — | 3,933,467 | ||||||||||||
Assets held-for-sale, net | 40,084 | — | — | 40,084 | ||||||||||||
Intercompany receivable | 250,279 | — | (250,279 | ) | — | |||||||||||
Investment in subsidiaries | 1,617,537 | — | (1,617,537 | ) | — | |||||||||||
Other assets | 42,547 | 2,569 | — | 45,116 | ||||||||||||
Total Assets | $ | 4,205,548 | $ | 2,082,159 | $ | (1,867,816 | ) | $ | 4,419,891 | |||||||
Liabilities and Stockholders' Equity | ||||||||||||||||
Liabilities | ||||||||||||||||
Current liabilities: | ||||||||||||||||
Accounts payable | $ | 85,000 | $ | 65,067 | $ | — | $ | 150,067 | ||||||||
Production tax liability | 35,902 | 1,752 | — | 37,654 | ||||||||||||
Fair value of derivatives | 79,302 | — | — | 79,302 | ||||||||||||
Funds held for distribution | 83,898 | 11,913 | — | 95,811 | ||||||||||||
Accrued interest payable | 11,812 | 3 | — | 11,815 | ||||||||||||
Other accrued expenses | 42,543 | 444 | — | 42,987 | ||||||||||||
Total current liabilities | 338,457 | 79,179 | — | 417,636 | ||||||||||||
Intercompany payable | — | 250,279 | (250,279 | ) | — | |||||||||||
Long-term debt | 1,151,932 | — | — | 1,151,932 | ||||||||||||
Deferred income taxes | 62,857 | 129,135 | — | 191,992 | ||||||||||||
Asset retirement obligations | 65,301 | 5,705 | — | 71,006 | ||||||||||||
Fair value of derivatives | 22,343 | — | — | 22,343 | ||||||||||||
Other liabilities | 57,009 | 324 | — | 57,333 | ||||||||||||
Total liabilities | 1,697,899 | 464,622 | (250,279 | ) | 1,912,242 | |||||||||||
Commitments and contingent liabilities | ||||||||||||||||
Stockholders' Equity | ||||||||||||||||
Stockholders' equity | ||||||||||||||||
Common shares | 659 | — | — | 659 | ||||||||||||
Additional paid-in capital | 2,503,294 | 1,766,775 | (1,766,775 | ) | 2,503,294 | |||||||||||
Retained earnings | 6,704 | (149,238 | ) | 149,238 | 6,704 | |||||||||||
Treasury shares | (3,008 | ) | — | — | (3,008 | ) | ||||||||||
Total stockholders' equity | 2,507,649 | 1,617,537 | (1,617,537 | ) | 2,507,649 | |||||||||||
Total Liabilities and Stockholders' Equity | $ | 4,205,548 | $ | 2,082,159 | $ | (1,867,816 | ) | $ | 4,419,891 |
Condensed Consolidating Statements of Operations | ||||||||||||||||
Three Months Ended March 31, 2018 | ||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | |||||||||||||
(in thousands) | ||||||||||||||||
Revenues | ||||||||||||||||
Crude oil, natural gas, and NGLs sales | $ | 233,494 | $ | 71,731 | $ | — | $ | 305,225 | ||||||||
Commodity price risk management loss, net | (47,240 | ) | — | — | (47,240 | ) | ||||||||||
Other income | 2,516 | 99 | — | 2,615 | ||||||||||||
Total revenues | 188,770 | 71,830 | — | 260,600 | ||||||||||||
Costs, expenses and other | ||||||||||||||||
Lease operating expenses | 21,362 | 8,274 | — | 29,636 | ||||||||||||
Production taxes | 16,081 | 4,088 | — | 20,169 | ||||||||||||
Transportation, gathering, and processing expenses | 3,231 | 4,082 | — | 7,313 | ||||||||||||
Exploration, geologic, and geophysical expense | 313 | 2,333 | — | 2,646 | ||||||||||||
Impairment of properties and equipment | 6 | 33,182 | — | 33,188 | ||||||||||||
General and administrative expense | 31,559 | 4,137 | — | 35,696 | ||||||||||||
Depreciation, depletion and amortization | 94,376 | 32,412 | — | 126,788 | ||||||||||||
Accretion of asset retirement obligations | 1,200 | 88 | — | 1,288 | ||||||||||||
Loss on sale of properties and equipment | 1,432 | — | — | 1,432 | ||||||||||||
Other expenses | 2,768 | — | — | 2,768 | ||||||||||||
Total costs, expenses and other | 172,328 | 88,596 | — | 260,924 | ||||||||||||
Income (loss) from operations | 16,442 | (16,766 | ) | — | (324 | ) | ||||||||||
Interest expense | (18,097 | ) | 568 | — | (17,529 | ) | ||||||||||
Interest income | 148 | — | — | 148 | ||||||||||||
Loss before income taxes | (1,507 | ) | (16,198 | ) | — | (17,705 | ) | |||||||||
Income tax benefit | 577 | 3,989 | — | 4,566 | ||||||||||||
Equity in loss of subsidiary | (12,209 | ) | — | 12,209 | — | |||||||||||
Net loss | $ | (13,139 | ) | $ | (12,209 | ) | $ | 12,209 | $ | (13,139 | ) |
Condensed Consolidating Statements of Operations | ||||||||||||||||
Three Months Ended March 31, 2017 | ||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | |||||||||||||
(in thousands) | ||||||||||||||||
Revenues | ||||||||||||||||
Crude oil, natural gas, and NGLs sales | $ | 170,739 | $ | 18,953 | $ | — | $ | 189,692 | ||||||||
Commodity price risk management gain, net | 80,704 | — | — | 80,704 | ||||||||||||
Other income | 3,297 | 14 | — | 3,311 | ||||||||||||
Total revenues | 254,740 | 18,967 | — | 273,707 | ||||||||||||
Costs, expenses and other | ||||||||||||||||
Lease operating expenses | 15,816 | 3,973 | — | 19,789 | ||||||||||||
Production taxes | 11,144 | 1,255 | — | 12,399 | ||||||||||||
Transportation, gathering, and processing expenses | 5,215 | 687 | — | 5,902 | ||||||||||||
Exploration, geologic, and geophysical expense | 271 | 683 | — | 954 | ||||||||||||
Impairment of properties and equipment | 604 | 1,589 | — | 2,193 | ||||||||||||
General and administrative expense | 23,529 | 2,786 | — | 26,315 | ||||||||||||
Depreciation, depletion and amortization | 101,738 | 7,578 | — | 109,316 | ||||||||||||
Accretion of asset retirement obligations | 1,685 | 83 | — | 1,768 | ||||||||||||
Gain on sale of properties and equipment | (160 | ) | — | — | (160 | ) | ||||||||||
Other expenses | 3,528 | — | — | 3,528 | ||||||||||||
Total costs, expenses and other | 163,370 | 18,634 | — | 182,004 | ||||||||||||
Income from operations | 91,370 | 333 | — | 91,703 | ||||||||||||
Interest expense | (19,597 | ) | 130 | — | (19,467 | ) | ||||||||||
Interest income | 240 | — | — | 240 | ||||||||||||
Income before income taxes | 72,013 | 463 | — | 72,476 | ||||||||||||
Income tax expense | (26,162 | ) | (168 | ) | — | (26,330 | ) | |||||||||
Equity in income of subsidiary | 295 | — | (295 | ) | — | |||||||||||
Net income | $ | 46,146 | $ | 295 | $ | (295 | ) | $ | 46,146 |
Condensed Consolidating Statements of Cash Flows | ||||||||||||||||
Three Months Ended March 31, 2018 | ||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | |||||||||||||
(in thousands) | ||||||||||||||||
Cash flows from operating activities | $ | 149,009 | $ | 56,140 | $ | — | $ | 205,149 | ||||||||
Cash flows from investing activities: | ||||||||||||||||
Capital expenditures for development of crude oil and natural gas properties | (97,286 | ) | (99,631 | ) | — | (196,917 | ) | |||||||||
Capital expenditures for other properties and equipment | (701 | ) | (365 | ) | — | (1,066 | ) | |||||||||
Acquisition of crude oil and natural gas properties, including settlement adjustments | (180,825 | ) | — | — | (180,825 | ) | ||||||||||
Proceeds from sale of properties and equipment | 20 | — | — | 20 | ||||||||||||
Proceeds from divestiture | 39,023 | — | — | 39,023 | ||||||||||||
Restricted cash | 1,249 | — | — | 1,249 | ||||||||||||
Intercompany transfers | (43,891 | ) | — | 43,891 | — | |||||||||||
Net cash from investing activities | (282,411 | ) | (99,996 | ) | 43,891 | (338,516 | ) | |||||||||
Cash flows from financing activities: | ||||||||||||||||
Proceeds from revolving credit facility | 35,000 | — | — | 35,000 | ||||||||||||
Repayment of revolving credit facility | (35,000 | ) | — | — | (35,000 | ) | ||||||||||
Purchase of treasury stock | (2,255 | ) | — | — | (2,255 | ) | ||||||||||
Other | (344 | ) | (35 | ) | — | (379 | ) | |||||||||
Intercompany transfers | — | 43,891 | (43,891 | ) | — | |||||||||||
Net cash from financing activities | (2,599 | ) | 43,856 | (43,891 | ) | (2,634 | ) | |||||||||
Net change in cash, cash equivalents, and restricted cash | (136,001 | ) | — | — | (136,001 | ) | ||||||||||
Cash, cash equivalents, and restricted cash, beginning of period | 189,925 | — | — | 189,925 | ||||||||||||
Cash, cash equivalents, and restricted cash, end of period | $ | 53,924 | $ | — | $ | — | $ | 53,924 |
Condensed Consolidating Statements of Cash Flows | ||||||||||||||||
Three Months Ended March 31, 2017 | ||||||||||||||||
Parent | Guarantor | Eliminations | Consolidated | |||||||||||||
(in thousands) | ||||||||||||||||
Cash flows from operating activities | $ | 131,661 | $ | 7,839 | $ | — | $ | 139,500 | ||||||||
Cash flows from investing activities: | ||||||||||||||||
Capital expenditures for development of crude oil and natural gas properties | (82,489 | ) | (47,337 | ) | — | (129,826 | ) | |||||||||
Capital expenditures for other properties and equipment | (890 | ) | 69 | — | (821 | ) | ||||||||||
Acquisition of crude oil and natural gas properties, including settlement adjustments | — | 6,181 | — | 6,181 | ||||||||||||
Proceeds from sale of properties and equipment | 737 | — | — | 737 | ||||||||||||
Purchase of short-term investments | (49,890 | ) | — | — | (49,890 | ) | ||||||||||
Intercompany transfers | (33,795 | ) | — | 33,795 | — | |||||||||||
Net cash from investing activities | (166,327 | ) | (41,087 | ) | 33,795 | (173,619 | ) | |||||||||
Cash flows from financing activities: | ||||||||||||||||
Purchase of treasury stock | (2,017 | ) | — | — | (2,017 | ) | ||||||||||
Other | (330 | ) | (10 | ) | — | (340 | ) | |||||||||
Intercompany transfers | — | 33,795 | (33,795 | ) | — | |||||||||||
Net cash from financing activities | (2,347 | ) | 33,785 | (33,795 | ) | (2,357 | ) | |||||||||
Net change in cash, cash equivalents, and restricted cash | (37,013 | ) | 537 | — | (36,476 | ) | ||||||||||
Cash, cash equivalents, and restricted cash, beginning of period | 240,487 | 3,613 | — | 244,100 | ||||||||||||
Cash, cash equivalents, and restricted cash, end of period | $ | 203,474 | $ | 4,150 | $ | — | $ | 207,624 |
Wells Operated by PDC | ||||||||||||||||||
Wattenberg Field | Delaware Basin | Total | ||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||
In-process as of December 31, 2017 | 87 | 80.1 | 13 | 12.2 | 100 | 92.3 | ||||||||||||
Wells spud | 35 | 32.7 | 8 | 6.8 | 43 | 39.5 | ||||||||||||
Acquired DUCs (1) | 12 | 11.0 | — | — | 12 | 11.0 | ||||||||||||
Wells turned-in-line | (29 | ) | (26.8 | ) | (7 | ) | (6.5 | ) | (36 | ) | (33.3 | ) | ||||||
In-process as of March 31, 2018 | 105 | 97.0 | 14 | 12.5 | 119 | 109.5 |
Wells Operated by Others | ||||||||||||||||||
Wattenberg Field | Delaware Basin | Total | ||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||
In-process as of December 31, 2017 | 14 | 2.6 | 8 | 1.0 | 22 | 3.6 | ||||||||||||
Wells spud | 22 | 3.7 | 3 | 0.1 | 25 | 3.8 | ||||||||||||
Acquired DUCs (operated at March 31, 2018) (1) | (3 | ) | (1.5 | ) | — | — | (3 | ) | (1.5 | ) | ||||||||
Wells turned-in-line | (4 | ) | (0.3 | ) | (2 | ) | (0.7 | ) | (6 | ) | (1.0 | ) | ||||||
In-process as of March 31, 2018 | 29 | 4.5 | 9 | 0.4 | 38 | 4.9 |
Low | High | ||||||
Operating Expenses | |||||||
Lease operating expenses ($/Boe) | $ | 2.75 | $ | 3.00 | |||
Transportation, gathering, and processing expenses ("TGP") ($/Boe) | $ | 0.60 | $ | 0.80 | |||
Production taxes (% of crude oil, natural gas, and NGLs sales) | 6 | % | 8 | % | |||
General and administrative expense ($/Boe) | $ | 3.40 | $ | 3.70 | |||
Estimated Price Realizations (% of NYMEX, excludes TGP) | |||||||
Crude oil | 91% | 95% | |||||
Natural gas | 55% | 60% | |||||
NGLs | 30% | 35% |
Three Months Ended March 31, | ||||||||||
2018 | 2017 | Percentage Change | ||||||||
(dollars in millions, except per unit data) | ||||||||||
Production | ||||||||||
Crude oil (MBbls) | 3,798 | 2,508 | 51.4 | % | ||||||
Natural gas (MMcf) | 19,587 | 15,584 | 25.7 | % | ||||||
NGLs (MBbls) | 1,846 | 1,543 | 19.6 | % | ||||||
Crude oil equivalent (MBoe) | 8,908 | 6,648 | 34.0 | % | ||||||
Average Boe per day (Boe) | 98,980 | 73,866 | 20.1 | % | ||||||
Crude Oil, Natural Gas and NGLs Sales | ||||||||||
Crude oil | $ | 226.4 | $ | 123.0 | 84.1 | % | ||||
Natural gas | 38.6 | 36.9 | 4.6 | % | ||||||
NGLs | 40.2 | 29.8 | 34.9 | % | ||||||
Total crude oil, natural gas, and NGLs sales | $ | 305.2 | $ | 189.7 | 60.9 | % | ||||
Net Settlements on Commodity Derivatives | ||||||||||
Crude oil | $ | (27.0 | ) | $ | (3.2 | ) | * | |||
Natural gas | 2.7 | 3.7 | (27.0 | )% | ||||||
NGLs (propane portion) | (1.7 | ) | — | * | ||||||
Total net settlements on derivatives | $ | (26.0 | ) | $ | 0.5 | * | ||||
Average Sales Price (excluding net settlements on derivatives) | ||||||||||
Crude oil (per Bbl) | $ | 59.62 | $ | 49.04 | 21.6 | % | ||||
Natural gas (per Mcf) | 1.97 | 2.37 | (16.9 | )% | ||||||
NGLs (per Bbl) | 21.80 | 19.29 | 13.0 | % | ||||||
Crude oil equivalent (per Boe) | 34.26 | 28.53 | 20.1 | % | ||||||
Average Costs and Expenses (per Boe) | ||||||||||
Lease operating expenses | $ | 3.33 | $ | 2.98 | 11.7 | % | ||||
Production taxes | 2.26 | 1.87 | 20.9 | % | ||||||
Transportation, gathering, and processing expenses | 0.82 | 0.89 | (7.9 | )% | ||||||
General and administrative expense | 4.01 | 3.96 | 1.3 | % | ||||||
Depreciation, depletion, and amortization | 14.23 | 16.44 | (13.4 | )% | ||||||
Lease Operating Expenses by Operating Region (per Boe) | ||||||||||
Wattenberg Field | $ | 3.02 | $ | 2.66 | 13.5 | % | ||||
Delaware Basin | 4.44 | 6.48 | (31.5 | )% | ||||||
Utica Shale (1) | 3.46 | 1.60 | 116.3 | % |
* | Percentage change is not meaningful. |
Three Months Ended | |||
March 31, 2018 | |||
(in millions) | |||
Increase in production | $ | 78.6 | |
Increase in average crude oil price | 40.2 | ||
Decrease in average natural gas price | (7.9 | ) | |
Increase in average NGLs price | 4.6 | ||
Total increase in crude oil, natural gas and NGLs sales revenue | $ | 115.5 |
Three Months Ended March 31, | |||||||||
Production by Operating Region | 2018 | 2017 | Percentage Change | ||||||
Crude oil (MBbls) | |||||||||
Wattenberg Field | 2,881 | 2,142 | 34.5 | % | |||||
Delaware Basin | 871 | 275 | * | ||||||
Utica Shale (1) | 46 | 91 | (49.5 | )% | |||||
Total | 3,798 | 2,508 | 51.4 | % | |||||
Natural gas (MMcf) | |||||||||
Wattenberg Field | 15,524 | 13,714 | 13.2 | % | |||||
Delaware Basin | 3,649 | 1,246 | * | ||||||
Utica Shale (1) | 414 | 624 | (33.7 | )% | |||||
Total | 19,587 | 15,584 | 25.7 | % | |||||
NGLs (MBbls) | |||||||||
Wattenberg Field | 1,428 | 1,358 | 5.2 | % | |||||
Delaware Basin | 383 | 131 | * | ||||||
Utica Shale (1) | 35 | 54 | (35.2 | )% | |||||
Total | 1,846 | 1,543 | 19.6 | % | |||||
Crude oil equivalent (MBoe) | |||||||||
Wattenberg Field | 6,896 | 5,786 | 19.2 | % | |||||
Delaware Basin | 1,862 | 613 | * | ||||||
Utica Shale (1) | 150 | 249 | (39.8 | )% | |||||
Total | 8,908 | 6,648 | 34.0 | % | |||||
Average crude oil equivalent per day (Boe) | |||||||||
Wattenberg Field | 76,623 | 64,288 | 19.2 | % | |||||
Delaware Basin | 20,690 | 6,811 | * | ||||||
Utica Shale (1) | 1,667 | 2,767 | (39.8 | )% | |||||
Total | 98,980 | 73,866 | 34.0 | % |
Three Months Ended March 31, 2018 | ||||||||
Crude Oil | Natural Gas | NGLs | Total | |||||
Wattenberg Field | 42% | 37% | 21% | 100% | ||||
Delaware Basin | 47% | 32% | 21% | 100% | ||||
Three Months Ended March 31, 2017 | ||||||||
Crude Oil | Natural Gas | NGLs | Total | |||||
Wattenberg Field | 37% | 40% | 23% | 100% | ||||
Delaware Basin | 45% | 34% | 21% | 100% |
Three Months Ended March 31, | |||||||||||
Weighted-Average Realized Sales Price by Operating Region | Percentage Change | ||||||||||
(excluding net settlements on derivatives) | 2018 | 2017 | |||||||||
Crude oil (per Bbl) | |||||||||||
Wattenberg Field | $ | 59.13 | $ | 49.12 | 20.4 | % | |||||
Delaware Basin | 61.34 | 49.28 | 24.5 | % | |||||||
Utica Shale (1) | 58.10 | 46.55 | 24.8 | % | |||||||
Weighted-average price | 59.62 | 49.04 | 21.6 | % | |||||||
Natural gas (per Mcf) | |||||||||||
Wattenberg Field | $ | 1.92 | $ | 2.38 | (19.3 | )% | |||||
Delaware Basin | 2.10 | 1.98 | 6.1 | % | |||||||
Utica Shale (1) | 2.68 | 2.98 | (10.1 | )% | |||||||
Weighted-average price | 1.97 | 2.37 | (16.9 | )% | |||||||
NGLs (per Bbl) | |||||||||||
Wattenberg Field | $ | 20.14 | $ | 18.64 | 8.0 | % | |||||
Delaware Basin | 27.76 | 22.58 | 22.9 | % | |||||||
Utica Shale (1) | 24.29 | 27.75 | (12.5 | )% | |||||||
Weighted-average price | 21.80 | 19.29 | 13.0 | % | |||||||
Crude oil equivalent (per Boe) | |||||||||||
Wattenberg Field | $ | 33.18 | $ | 28.19 | 17.7 | % | |||||
Delaware Basin | 38.52 | 30.93 | 24.5 | % | |||||||
Utica Shale (1) | 30.98 | 30.55 | 1.4 | % | |||||||
Weighted-average price | 34.26 | 28.53 | 20.1 | % |
For the three months ended March 31, 2018 | Average NYMEX Price | Average Realized Price Before Transportation, Gathering and Processing Expenses | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | Average Transportation, Gathering and Processing Expenses | Average Realized Price After Transportation, Gathering and Processing Expenses | Average Realization Percentage After Transportation, Gathering, and Processing Expenses | ||||||||||||||||
Crude oil (per Bbl) | $ | 62.87 | $ | 59.62 | 95 | % | $ | 0.67 | $ | 58.95 | 94 | % | ||||||||||
Natural gas (per MMBtu) | 3.00 | 1.97 | 66 | % | 0.22 | 1.75 | 58 | % | ||||||||||||||
NGLs (per Bbl) | 62.87 | 21.80 | 35 | % | 0.24 | 21.56 | 34 | % | ||||||||||||||
Crude oil equivalent (per Boe) | 46.43 | 34.26 | 74 | % | 0.82 | 33.44 | 72 | % | ||||||||||||||
For the three months ended March 31, 2017 | Average NYMEX Price | Average Realized Price Before Transportation, Gathering and Processing Expenses | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | Average Transportation, Gathering and Processing Expenses | Average Realized Price After Transportation, Gathering and Processing Expenses | Average Realization Percentage After Transportation, Gathering, and Processing Expenses | ||||||||||||||||
Crude oil (per Bbl) | $ | 51.92 | $ | 49.04 | 94 | % | $ | 1.58 | $ | 47.46 | 91 | % | ||||||||||
Natural gas (per MMBtu) | 3.32 | 2.37 | 71 | % | 0.06 | 2.31 | 70 | % | ||||||||||||||
NGLs (per Bbl) | 51.92 | 19.29 | 37 | % | 0.22 | 19.07 | 37 | % | ||||||||||||||
Crude oil equivalent (per Boe) | 39.42 | 28.53 | 72 | % | 0.89 | 27.64 | 70 | % |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(in millions) | |||||||
Commodity price risk management gain (loss), net: | |||||||
Net settlements of commodity derivative instruments: | |||||||
Crude oil fixed price swaps and collars | $ | (26.8 | ) | $ | (3.2 | ) | |
Crude oil basis protection swaps | (0.2 | ) | — | ||||
Natural gas fixed price swaps and collars | 0.1 | 3.6 | |||||
Natural gas basis protection swaps | 2.6 | 0.1 | |||||
NGLs (propane portion) fixed price swaps | (1.7 | ) | — | ||||
Total net settlements of commodity derivative instruments | (26.0 | ) | 0.5 | ||||
Change in fair value of unsettled commodity derivative instruments: | |||||||
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments | 20.3 | 9.1 | |||||
Crude oil fixed price swaps, collars, and rollfactors | (52.6 | ) | 56.2 | ||||
Natural gas fixed price swaps and collars | (0.8 | ) | 11.2 | ||||
Natural gas basis protection swaps | 10.6 | 3.3 | |||||
NGLs (propane portion) fixed price swaps | 1.3 | 0.4 | |||||
Net change in fair value of unsettled commodity derivative instruments | (21.2 | ) | 80.2 | ||||
Total commodity price risk management gain (loss), net | $ | (47.2 | ) | $ | 80.7 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(in millions) | |||||||
Impairment of proved and unproved properties | $ | 33.1 | $ | 2.1 | |||
Amortization of individually insignificant unproved properties | 0.1 | 0.1 | |||||
Impairment of crude oil and natural gas properties | $ | 33.2 | $ | 2.2 |
Three Months Ended | ||||
March 31, 2018 | ||||
(in thousands) | ||||
Increase in production | $ | 32,005 | ||
Decrease in weighted-average depreciation, depletion, and amortization rates | (15,035 | ) | ||
Total increase in DD&A expense related to crude oil and natural gas properties | $ | 16,970 |
Three Months Ended March 31, | ||||||||
Operating Region/Area | 2018 | 2017 | ||||||
(per Boe) | ||||||||
Wattenberg Field | $ | 13.53 | $ | 16.94 | ||||
Delaware Basin | 16.91 | 11.46 | ||||||
Utica Shale (1) | — | 11.24 | ||||||
Total weighted-average | $ | 14.01 | $ | 16.22 |
• | 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. |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
(in millions) | |||||||
Adjusted cash flows from operations: | |||||||
Net cash from operating activities | $ | 205.1 | $ | 139.5 | |||
Changes in assets and liabilities | (30.2 | ) | (25.8 | ) | |||
Adjusted cash flows from operations | $ | 174.9 | $ | 113.7 | |||
Adjusted net income (loss): | |||||||
Net income (loss) | $ | (13.1 | ) | $ | 46.1 | ||
(Gain) loss on commodity derivative instruments | 47.2 | (80.7 | ) | ||||
Net settlements on commodity derivative instruments | (26.0 | ) | 0.5 | ||||
Tax effect of above adjustments | (5.1 | ) | 30.0 | ||||
Adjusted net income (loss) | $ | 3.0 | $ | (4.1 | ) | ||
Net income (loss) to adjusted EBITDAX: | |||||||
Net income (loss) | $ | (13.1 | ) | $ | 46.1 | ||
(Gain) loss on commodity derivative instruments | 47.2 | (80.7 | ) | ||||
Net settlements on commodity derivative instruments | (26.0 | ) | 0.5 | ||||
Non-cash stock-based compensation | 5.3 | 4.5 | |||||
Interest expense, net | 17.4 | 19.2 | |||||
Income tax expense (benefit) | (4.6 | ) | 26.3 | ||||
Impairment of properties and equipment | 33.2 | 2.2 | |||||
Exploration, geologic, and geophysical expense | 2.6 | 1.0 | |||||
Depreciation, depletion, and amortization | 126.8 | 109.3 | |||||
Accretion of asset retirement obligations | 1.3 | 1.8 | |||||
Adjusted EBITDAX | $ | 190.1 | $ | 130.2 | |||
Cash from operating activities to adjusted EBITDAX: | |||||||
Net cash from operating activities | $ | 205.1 | $ | 139.5 | |||
Interest expense, net | 17.4 | 19.2 | |||||
Amortization of debt discount and issuance costs | (3.2 | ) | (3.2 | ) | |||
Gain (loss) on sale of properties and equipment | (1.4 | ) | 0.2 | ||||
Exploration, geologic, and geophysical expense | 2.6 | 1.0 | |||||
Other | (0.2 | ) | (0.7 | ) | |||
Changes in assets and liabilities | (30.2 | ) | (25.8 | ) | |||
Adjusted EBITDAX | $ | 190.1 | $ | 130.2 |
Three Months Ended | Year Ended | ||||||
March 31, 2018 | December 31, 2017 | ||||||
Average NYMEX Index Price: | |||||||
Crude oil (per Bbl) | $ | 62.87 | $ | 50.95 | |||
Natural gas (per MMBtu) | 3.00 | 3.11 | |||||
Average Sales Price Realized: | |||||||
Excluding net settlements on commodity derivatives | |||||||
Crude oil (per Bbl) | $ | 59.62 | $ | 48.45 | |||
Natural gas (per Mcf) | 1.97 | 2.21 | |||||
NGLs (per Bbl) | 21.80 | 18.59 |
Period | Total Number of Shares Purchased (1) | Average Price Paid per Share | |||||
January 1 - 31, 2018 | 34,846 | $ | 55.37 | ||||
February 1 - 28, 2018 | 6,511 | 50.04 | |||||
March 1 - 31, 2018 | — | — | |||||
Total first quarter 2018 purchases | 41,357 | $ | 54.53 | ||||
(1) | Purchases 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. |
Incorporated by Reference | ||||||||||||
Exhibit Number | Exhibit Description | Form | SEC File Number | Exhibit | Filing Date | Filed Herewith | ||||||
31.1 | X | |||||||||||
31.2 | X | |||||||||||
32.1* | ||||||||||||
99.1 | X | |||||||||||
99.2 | X | |||||||||||
99.3 | X | |||||||||||
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 |
PDC Energy, Inc. | |
(Registrant) | |
Date: May 2, 2018 | /s/ Barton R. Brookman |
Barton R. Brookman | |
President and Chief Executive Officer | |
(principal executive officer) | |
/s/ R. Scott Meyers | |
R. Scott Meyers | |
Senior Vice President and Chief Financial Officer | |
(principal financial officer) | |
1. | I have reviewed this Quarterly Report on Form 10-Q of PDC Energy, Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: | May 2, 2018 |
/s/ Barton R. Brookman | |
Barton R. Brookman | |
President and Chief Executive Officer | |
(principal executive officer) |
1. | I have reviewed this Quarterly Report on Form 10-Q of PDC Energy, Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: | May 2, 2018 |
/s/ R. Scott Meyers | |
R. Scott Meyers | |
Senior Vice President and Chief Financial Officer | |
(principal financial officer) |
1. | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Barton R. Brookman | May 2, 2018 | |
Barton R. Brookman | ||
President and Chief Executive Officer | ||
(principal executive officer) | ||
/s/ R. Scott Meyers | May 2, 2018 | |
R. Scott Meyers | ||
Senior Vice President and Chief Financial Officer | ||
(principal financial officer) |
• | If the Company is ranked at or above the 90th percentile of the Peer Companies, including the Company, 200% of the Target Award |
• | If the Company is ranked at the 50th percentile or median of the Peer Companies, including the Company, 100% of the Target Award |
• | If the Company is ranked at the 25th percentile of the Peer Companies, including the Company, 50% of the Target Award |
• | If the Company is ranked below the 25th percentile of the Peer Companies, including the Company, no award will be paid |
• | Callon Petroleum Company (CPE) |
• | Carrizo Oil & Gas Inc. (CRZO) |
• | Diamondback Energy, Inc. (FANG) |
• | Energen Corporation (EGN) |
• | Laredo Petroleum Holdings, Inc. (LPI) |
• | Matador Resources Company (MTDR) |
• | Newfield Exploration Company (NFX) |
• | Oasis Petroleum Inc. (OAS) |
• | Parsley Energy, Inc. (PE) |
• | QEP Resources, Inc. (QEP) |
• | RSP Permian, Inc. (RSPP) |
• | SM Energy Company (SM) |
• | SRC Energy Inc. (SRCI) |
• | WPX Energy, Inc. (WPX) |
Grant Date | February 21, 2018 |
Number of Restricted Stock Units | __________. |
Vesting Schedule | Except as set forth below, your Restricted Stock Units shall vest in annual installments over three (3) years provided you remain in Continuous Service from the Grant Date to the applicable “Scheduled Vesting Date,” as set forth below: The term “Continuous Service” shall mean your uninterrupted service to the Company or an Affiliate as an Employee, Non-Employee Director, or consultant. The Committee shall determine in its discretion whether and when your Continuous Service has ended (including as a result of any leave of absence); provided, however, that your Continuous Service shall not be deemed to have ended in the event you retire or otherwise terminate as an Employee but continue to perform services for the Company as a Non-Employee Director or consultant. |
Special Vesting Events | Certain terminations of Continuous Service In the event of the termination of your Continuous Service due to death or Disability, as defined in the Plan, or due to a termination without Cause or your voluntary resignation for Good Reason (as the terms “Cause” and “Good Reason” are defined in your employment agreement, if any, or if none, in any Company severance plan in which you are a participant), any unvested Restricted Stock Units will vest as of your date of termination. Change in Control In the event of a “Change in Control” (as defined in the Plan) while you are in the Continuous Service of the Company, any non-vested Restricted Stock Units will vest in full. |
Payment | The Company shall issue to you one share of Common Stock for each Restricted Stock Unit that vests hereunder, with the delivery of such Common Stock to occur upon the first of: (i) the Scheduled Vesting Date of such Restricted Stock Units, (ii) your “Separation from Service” (as defined in the Plan), or (ii) a Change in Control (the first event to occur being the “Applicable Payment Event”). Notwithstanding the foregoing, if and only if (i) the Restricted Stock Units provided hereunder are non-qualified deferred compensation subject to Code Section 409A, (ii) you are a “specified employee” as defined for purposes of Code Section 409A, and (iii) distribution would otherwise be made on the date of the your Separation from Service, then distribution shall be delayed until the sooner of (x) the date that is 6 months and one day following the date of such Separation from Service, (y) your death, or (z) such sooner date as may be permitted under Code Section 409A. |
Dividend Equivalent Right | Restricted Stock Units shall have related dividend equivalent rights, which shall entitle you to receive an additional amount in cash in respect of your vested Restricted Stock Units equal to the value of all dividends and distributions made between the Grant Date and the payment date with respect to a number of shares of Common Stock equal to the number of Restricted Stock Units paid on such date (the “Dividend Equivalent Amounts”). The Dividend Equivalent Amounts shall be accumulated and paid at the same time as the vested Restricted Stock Units to which they relate. In the event the related Restricted Stock Units are forfeited, the accumulated Dividends Equivalent Amounts will also be forfeited. |
Stockholder Rights | You have no stockholder rights with respect to the Restricted Stock Units. |
Other Terms and Conditions | Are set forth in the accompanying Restricted Stock Unit Grant Terms and Conditions and the Plan. |
Grant Date | [GRANT DATE] |
Number of Restricted Stock Units | __________. |
Vesting Schedule | Except as set forth below, your Restricted Stock Units will vest in accordance with the following schedule, subject to the condition that you provide continued service on the Board from the Grant Date to the applicable “Scheduled Vesting Date” set forth below. |
Special Vesting Events | Notwithstanding the above, any unvested Restricted Stock Units shall become vested in full upon the occurrence of any of the following: |
(1) your retirement from the Board in compliance with the Board’s retirement policy as then in effect; (2) the termination of your service on the Board as a result of your not being nominated for reelection by the Board; (3) the termination of your service on the Board because of your resignation or failure to stand for reelection with the consent of the Company’s Board (which means approval by at least 80% of the directors voting, with you abstaining); (4) the termination of your service on the Board because you, although nominated for reelection by the Board, are not reelected by the Company’s stockholders; (5) the termination of your service on the Board because of (i) your resignation at the request of the Nominating and Governance Committee of the Board (or successor committee), (ii) your removal by action of the stockholders or by the Board, or (iii) a Change in Control of the Company; or (6) the termination of your service on the Board because of death or Disability. A termination of your service on the Board for any reason not described in (1) through (6) above (including, but not limited to, a removal or resignation for Cause) will result in a forfeiture on the date of termination of all Restricted Stock Units not previously vested. | |
Payment | The Company shall issue to you one share of Common Stock for each Restricted Stock Unit that vests hereunder, with the delivery of such Common Stock to occur upon the first of: (i) the Scheduled Vesting Date of such Restricted Stock Units, (ii) your Separation from Service (as defined in the Plan), or (ii) a Change in Control (the first event to occur being the “Applicable Payment Event”). |
Dividend Equivalent Right | Restricted Stock Units shall have related dividend equivalent rights, which shall entitle you to receive an additional amount in cash in respect of your vested Restricted Stock Units equal to the value of all dividends and distributions made between the Grant Date and the payment date with respect to a number of shares of Common Stock equal to the number of Restricted Stock Units paid on such date (the “Dividend Equivalent Amounts”). The Dividend Equivalent Amounts shall be accumulated and paid at the same time as the vested Restricted Stock Units to which they relate. In the event the related Restricted Stock Units are forfeited, the accumulated Dividends Equivalent Amounts will also be forfeited. |
Stockholder Rights | You have no stockholder rights with respect to the Restricted Stock Units. |
Other Terms and Conditions | Are set forth in the accompanying Restricted Stock Unit Grant Terms and Conditions and the Plan. |
Document and Entity Information Document Document - shares |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Apr. 20, 2018 |
|
Entity Information [Line Items] | ||
Entity Registrant Name | PDC ENERGY, INC. | |
Entity Central Index Key | 0000077877 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2018 | |
Document Fiscal Year Focus | 2018 | |
Document Fiscal Period Focus | Q1 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 66,065,856 |
Balance Sheet Parenthetical (Parentheticals) - $ / shares |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 150,000,000 | 150,000,000 |
Common stock, shares issued | 65,999,010 | 65,955,080 |
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred Stock, Shares Authorized | 50,000,000 | 50,000,000 |
Preferred Stock, Shares Issued | 0 | 0 |
Treasury shares, at cost | 29,255 | 55,927 |
NATURE OF OPERATIONS AND BASIS OF PRESENTATION |
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Mar. 31, 2018 | |
NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract] | |
Nature of Operations | NATURE OF OPERATIONS AND BASIS OF PRESENTATION PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores, and develops properties for the production of crude oil, natural gas, and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are currently focused in the Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the three months ended March 31, 2018. As of March 31, 2018, we owned an interest in approximately 3,000 gross productive wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Our gas marketing segment does not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented. The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues, and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2017 condensed consolidated balance sheet data was derived from audited statements, but does not include all disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2017 Form 10-K. Our results of operations and cash flows for the three months ended March 31, 2018 are not necessarily indicative of the results to be expected for the full year or any other future period. |
Recent Accounting Standards |
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Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Recently Adopted Accounting Standard 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 standard has been updated and now includes technical corrections. 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. We adopted the standard effective January 1, 2018. In order to evaluate the impact that the adoption of the revenue standard had on our consolidated financial statements, we performed a comprehensive review of our significant revenue streams. The focus of this review included, among other things, the identification of the significant contracts and other arrangements we have with our customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of the transaction price. We also reviewed our current accounting policies, procedures, and controls with respect to these contracts and arrangements to determine what changes, if any, would be required by the adoption of the revenue standard. We determined that we would adopt the standard under the modified retrospective method. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. The adoption of this standard impacted our condensed consolidated statements of cash flows. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the condensed consolidated balance sheets at March 31, 2018 and December 31, 2017, which sum to the total of cash, cash equivalents, and restricted cash in the condensed consolidated statements of cash flows:
Restricted cash is included in other assets on the condensed consolidated balance sheets at March 31, 2018 and December 31, 2017. We did not have any cash classified as restricted cash at March 31, 2017 or December 31, 2016. Recently Issued Accounting Standards In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. The standard has been updated and now includes amendments. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. |
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Description of New Accounting Pronouncements Not yet Adopted [Text Block] | In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. The standard has been updated and now includes amendments. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. |
Business Combination Business Combinations (Notes) |
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Business Combinations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Combination Disclosure [Text Block] | BUSINESS COMBINATION In January 2018, we closed the acquisition of properties from Bayswater Exploration and Production LLC (the "Bayswater Acquisition") for approximately $201.8 million in cash, including $21.0 million deposited into an escrow account in September 2017, subject to certain customary post-closing adjustments. The $21.0 million deposit was included in other assets on our December 31, 2017 condensed consolidated balance sheet. We acquired approximately 7,400 net acres, approximately 220 gross drilling locations, and 24 operated horizontal wells that were either drilled uncompleted wells ("DUCs") or in-process wells at the time of closing. The details of the estimated purchase price and the preliminary allocation of the purchase price for the transaction, are presented below (in thousands):
This acquisition was accounted for under the acquisition method. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, lease terms and expirations, and a market-based weighted-average cost of capital rate. Within the unproved properties, the allocation of the value to the underlying leases also requires significant judgment and is based on a combination of comparable market transactions, the term and conditions associated with the individual leases, our ability and intent to develop specific leases, and our initial assessment of the underlying relative value of the leases given our knowledge of the geology at the time of closing. These inputs require significant judgments and estimates by management at the time of the valuation and were the most sensitive and subject to change. The results of operations for the Bayswater Acquisition for the three months ended March 31, 2018 have been included in our condensed consolidated financial statements. Pro forma results of operations for the Bayswater Acquisition showing results as if the acquisition had been completed as of January 1, 2017 would not have been material to our condensed consolidated financial statements for the three months ended March 31, 2017. |
Revenue Recognition (Notes) |
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Revenue from Contract with Customer [Text Block] | REVENUE RECOGNITION On January 1, 2018, we adopted the new accounting standard that was issued by the FASB and the International Accounting Standards Board that converged their standard on revenue recognition and provides a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all the related amendments (“new revenue standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the standard would have reduced our crude oil, natural gas, and NGLs sales by approximately $2.5 million in the first quarter of 2017 with a corresponding decrease in transportation, gathering, and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas, and NGLs sales and our transportation, processing, and gathering expenses for the three months ended March 31, 2017, we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the new standard to have a significant impact on our net income going forward. Crude oil, natural gas, and NGLs revenues are recognized when we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits, from the crude oil, natural gas, or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas, and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the three months ended March 31, 2018 and 2017 the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. Our crude oil, natural gas, and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas, or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering, or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas, or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering, and processing expenses. Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the new revenue recognition standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the new revenue standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the new revenue standard will be recognized using the net-back method. As discussed above, we enter into agreements for the sale, transportation, gathering, and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and our natural gas average NYMEX pricing is based upon first-of-the-month index prices as this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. Disaggregated Revenue. The following table presents crude oil, natural gas, and NGLs sales disaggregated by commodity and operating region for the three months ended March 31, 2018 and 2017 (in thousands):
________________ (1) In March 2018, we completed the sale of our Utica Shale properties. (2) As we have elected the modified retrospective method of adoption, revenues for the three months ended March 31, 2017 have not been restated for the new revenue recognition standard. Such amounts would not have been material. Contract Assets. Contract assets include material contributions in aid of construction ("CIAC"), which are common in purchase/purchase and processing agreements with midstream service providers that are our customers. Generally, the intent of the payments is to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets that are classified as current assets are included in prepaid expenses and other current assets on our condensed consolidated balance sheet. Contract assets that are classified as long-term are included in other assets on our condensed consolidated balance sheet. The contract assets will be amortized as a reduction to crude oil, natural gas, or NGLs sales revenue during the periods that the related production is transferred to the customer. The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas, and NGLs sales revenue for the three months ended March 31, 2018:
Customer Accounts Receivable. Our accounts receivable include amounts billed and currently due from sales of our crude oil, natural gas, and NGLs production. Our gross accounts receivable balance from crude oil, natural gas, and NGLs sales at March 31, 2018 and December 31, 2017 was $145.3 million and $154.3 million, respectively. Historically, we have not recorded a significant amount of write-offs related to our accounts receivable from sales of our crude oil, natural gas, and NGLs sales, therefore; we did not record an allowance for doubtful accounts for these receivables at March 31, 2018 or December 31, 2017. |
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Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block] | On January 1, 2018, we adopted the new accounting standard that was issued by the FASB and the International Accounting Standards Board that converged their standard on revenue recognition and provides a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all the related amendments (“new revenue standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the standard would have reduced our crude oil, natural gas, and NGLs sales by approximately $2.5 million in the first quarter of 2017 with a corresponding decrease in transportation, gathering, and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas, and NGLs sales and our transportation, processing, and gathering expenses for the three months ended March 31, 2017, we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the new standard to have a significant impact on our net income going forward. Crude oil, natural gas, and NGLs revenues are recognized when we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits, from the crude oil, natural gas, or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas, and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the three months ended March 31, 2018 and 2017 the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. Our crude oil, natural gas, and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas, or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering, or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas, or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering, and processing expenses. Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the new revenue recognition standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the new revenue standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the new revenue standard will be recognized using the net-back method. As discussed above, we enter into agreements for the sale, transportation, gathering, and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and our natural gas average NYMEX pricing is based upon first-of-the-month index prices as this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. |
Fair Value Measurements and Disclosures |
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Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value, Measurement Inputs, Disclosure | FAIR VALUE OF FINANCIAL INSTRUMENTS Determination of Fair Value Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. Derivative Financial Instruments We measure the fair value of our derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors, and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. We validate our fair value measurement through the review of counterparty statements and other supporting documentation, determination that the source of the inputs is valid, corroboration of the original source of inputs through access to multiple quotes, if available, or other information, and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and 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:
The following table presents a reconciliation of our Level 3 assets measured at fair value:
The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by this report. Non-Derivative Financial Assets and Liabilities The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. We utilize fair value on a nonrecurring basis to review our proved 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 assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. 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, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of March 31, 2018.
The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the related vehicle lease. Concentration of Risk Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our commodity derivative contracts. An insignificant portion of our commodity derivative instruments may be with other counterparties. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at March 31, 2018, taking into account the estimated likelihood of nonperformance. Cash and Cash Equivalents. We consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of the FDIC insurance limits at March 31, 2018 and December 31, 2017. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also major lenders under our revolving credit facility. |
Derivative Financial Instruments |
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Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Text Block] | COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas, and NGLs. To manage a portion of our exposure to price volatility from producing crude oil, natural gas, and propane, which is an element of our NGLs, we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases. We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of March 31, 2018, we had derivative instruments, which were comprised of collars, fixed-price swaps, and basis protection swaps, in place for a portion of our anticipated 2018 and 2019 production. Our commodity derivative contracts have been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. As of March 31, 2018, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
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We have not elected to designate any of our derivative instruments as cash flow hedges, and therefore these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the condensed consolidated statements of operations. The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets:
The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:
Net settlements of commodity derivatives and net change in fair value of unsettled derivatives decreased for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017 as a result of the increase in future commodity prices during the first quarter of 2018 compared to a decrease during the first quarter of 2017. 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. 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:
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Properties and Equipment |
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Oil and Gas Property [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment Disclosure | PROPERTIES AND EQUIPMENT The following table presents the components of properties and equipment, net of accumulated depreciation, depletion, and amortization ("DD&A"):
The following table presents impairment charges recorded for crude oil and natural gas properties:
During the three months ended March 31, 2018, we recorded impairment charges of $26.9 million, primarily related to certain unproved Delaware Basin leasehold positions that expired during the three months ended March 31, 2018. Additionally, we corrected an error in our calculation of the unproved properties and goodwill impairment originally reported in the quarter ended September 30, 2017. The correction of the error resulted in an additional impairment charge of $6.3 million, recorded in the three months ended March 31, 2018, which we have included in the impairment of properties and equipment expense line in our condensed consolidated statement of operations. We evaluated the error under the guidance of Accounting Standards Codification 250, Accounting Changes and Error Corrections ("ASC 250"). Based on the guidance in ASC 250, we determined that the impact of the error did not have a material impact to our previously-issued financial statements or those of the period of correction. Utica Shale Divestiture. In March 2018, we completed the sale of our Utica Shale properties (the "Utica Shale Divestiture") for net cash proceeds of approximately $39.0 million, subject to certain customary post-closing adjustments. We recorded a loss on sale of properties and equipment of $1.4 million for the three months ended March 31, 2018. The divestiture of the Utica Shale properties did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for it as a discontinued operation. Classification of Assets as Held-for-Sale. Assets held-for-sale as of March 31, 2018 were $1.6 million for a field office facility. We subsequently sold the field office facility in April 2018 for $1.9 million and will record a gain on sale of properties and equipment of $0.3 million during the second quarter of 2018. Assets held-for-sale as of December 31, 2017 included $36.8 million and $3.3 million, representing our Utica Shale properties and field office facilities and a separate parcel of land, respectively. The following table presents balance sheet data related to assets held-for-sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities that are expected to be assumed by the purchasers:
Suspended Well Costs. We have spud three wells in the Delaware Basin for which we are unable to make a final determination regarding whether proved reserves can be associated with the wells as of March 31, 2018 as the wells had not been completed as of that date. Therefore, we have classified the capitalized costs of the wells as suspended well costs as of March 31, 2018 while we continue to conduct completion and testing operations to determine the existence of proved reserves. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the condensed consolidated balance sheets:
Exploration, geologic, and geophysical expense. Exploration, geologic, and geophysical expense of $2.6 million during the three months ended March 31, 2018 was primarily related to the purchase of seismic data related to unproved acreage and lease costs associated with certain delayed drilling in the Delaware Basin. Exploration, geologic, and geophysical expense of $1.0 million during the three months ended March 31, 2017 was primarily related to drilling pilot holes in the Delaware Basin. |
Other Accrued Expenses Other Accrued Expenses (Notes) |
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Other Income and Other Expense Disclosure [Text Block] | OTHER ACCRUED EXPENSES AND OTHER LIABILITIES Other Accrued Expenses. The following table presents the components of other accrued expenses as of:
Other Liabilities. The following table presents the components of other liabilities as of:
On January 31, 2018, we received a payment of $24.1 million from Saddle Butte Rockies Midstream, LLC for the execution of an amendment to an existing crude oil purchase and sale agreement signed in December 2017. The amendment was effective contingent upon certain events which occurred in late January 2018. The amendment, among other things, dedicates crude oil from the majority of our Wattenberg Field acreage to Saddle Butte's gathering lines and extends the term of the agreement through December 2029. Subsequent to the receipt of this payment, Saddle Butte was purchased by Black Diamond Gathering, LLC. The short-term portion of the deferred oil gathering credit is included in other accrued expenses and the long-term portion is included in other liabilities on our condensed consolidated balance sheet as of March 31, 2018. The payment will be amortized using the straight-line method over the life of the amendment. Amortization charges totaling approximately $0.4 million for the three months ended March 31, 2018 related to the deferred oil gathering credit are included as a reduction to transportation, gathering, and processing expenses on our condensed consolidated statements of operations. |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Debt | LONG-TERM DEBT Long-term debt consisted of the following as of:
Senior Notes 2021 Convertible Notes. In September 2016, we issued $200 million of 1.125% convertible notes due 2021 (the "2021 Convertible Notes") in a public offering. The maturity for the payment of principal is September 15, 2021. Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15. The conversion stock price at maturity is $85.39 per share. We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, priced on the same day we issued the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes have been capitalized as debt issuance costs. As of March 31, 2018, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using an effective interest rate of 5.8 percent. Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash, or a combination of cash and shares of our common stock. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares of our common stock, with cash paid in lieu of fractional shares. 2024 Senior Notes. In September 2016, we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”) in a private placement to qualified institutional buyers. In May 2017, in accordance with the registration rights agreement that we entered into with the initial purchasers when we issued the 2024 Senior Notes, we filed a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms, and we completed the exchange offer in September 2017. The 2024 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on March 15 and September 15. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. 2026 Senior Notes. In November 2017, we issued $600 million aggregate principal amount of 5.75% senior notes due May 15, 2026, in a private placement to qualified institutional buyers. The 2026 Senior Notes are governed by an indenture dated November 29, 2017 between us and the U.S. Bank National Association, as trustee. The maturity for the payment of principal is May 15, 2026. Interest at the rate of 5.75% per year is payable in cash semiannually in arrears on each May 15 and November 15, commencing on May 15, 2018. Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. Our wholly-owned subsidiary PDC Permian, Inc. guarantees our obligations under the 2021 Convertible Notes, the 2026 Senior Notes, and the 2024 Senior Notes (collectively, the "Notes"). Accordingly, condensed consolidating financial information for PDC and PDC Permian, Inc. is presented in the footnote titled Subsidiary Guarantor. As of March 31, 2018, we were in compliance with all covenants related to the Notes, and expect to remain in compliance throughout the next 12-month period. Revolving Credit Facility The revolving credit facility is available for working capital requirements, capital investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility matures in May 2020 and provides for a maximum of $1.0 billion in allowable borrowing capacity, subject to the borrowing base and certain limitations under our senior notes. 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. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by 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. In May and October 2017, we entered into the Fifth and Sixth Amendments, respectively, to the Third Amended and Restated Credit Agreement to amend the revolving credit facility to reflect increases in the borrowing base. The Fifth amendment reflected an increase of the borrowing base from $700 million to $950 million and the Sixth Amendment amended the revolving credit facility to allow the borrowing base to increase above the borrowing capacity of $1.0 billion. In addition, the Fifth Amendment made changes to certain of the covenants in the existing agreement as well as other administrative changes. We elected to increase the borrowing base to $1.1 billion for our November 2017 borrowing base redetermination and have elected to maintain a $700 million commitment level as of the date of this report. In April 2018, we began negotiations with our bank group to enter into the Fourth Amended and Restated Credit Agreement, and we anticipate closing to occur by the end of May 2018. This agreement is expected to replace the Third Amended and Restated Credit Agreement. Following the amendment and restatement, the facility is expected to mature in May 2023. As of March 31, 2018 and December 31, 2017, debt issuance costs related to our revolving credit facility were $5.5 million and $6.2 million, respectively, and are included in other assets on the condensed consolidated balance sheets. We had no outstanding balance on our revolving credit facility as of March 31, 2018 or December 31, 2017. The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium), or at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin, and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of March 31, 2018, the applicable interest margin is 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment fee is 0.5 percent. Principal payments are generally not required until the revolving credit facility expires in May 2020 unless the borrowing base falls below the outstanding balance. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of March 31, 2018, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. As defined by the revolving credit facility, our leverage ratio was 1.7 and our current ratio was 2.5 as of March 31, 2018. |
Capital Leases (Notes) |
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Capital Leases in Financial Statements of Lessee Disclosure [Text Block] | CAPITAL LEASES We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90 percent of the fair value of the leased vehicles at inception of the lease. The following table presents vehicles under capital lease as of:
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:
Short-term capital lease obligations are included in other accrued expenses on the condensed consolidated balance sheets and long-term capital lease obligations are included in other liabilities on the condensed consolidated balance sheets. |
Income Taxes |
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Income Tax Disclosure [Abstract] | |
Income Tax Disclosure | INCOME TAXES We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual annual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective income tax rate, adjusted for the effect of discrete items. The effective income tax rate for the three months ended March 31, 2018 was a 25.8 percent benefit on loss compared to a 36.3 percent expense on income for the three months ended March 31, 2017. The effective income tax rate for the three months ended March 31, 2018, is based upon a full year forecasted tax expense on income. The effective income tax rate for the three months ended March 31, 2018 includes discrete income tax benefits of $0.2 million relating to the excess tax benefit recognized with the vesting of stock awards during the three months ended March 31, 2018, which resulted in a 1.2 percent increase to our effective tax rate. The federal corporate statutory income tax rate decreased from 35 percent in 2017 to 21 percent in 2018 resulting from the 2017 Tax Cuts and Jobs Act (the "2017 Tax Act"). The effective income tax rate for the three months ended March 31, 2018 is based upon a full year forecasted tax expense on income and is greater than the statutory federal tax rate, primarily due to state taxes, nondeductible officers’ compensation, and nondeductible lobbying expenses, partially offset by stock-based compensation tax deductions. We anticipate the potential for increased periodic volatility in future effective tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items. The effective tax rate for the three months ended March 31, 2017 is based upon a full year forecasted tax expense on income and is greater than the statutory federal tax rate, primarily due to state taxes, nondeductible officers’ compensation and nondeductible lobbying expenses, partially offset by stock-based compensation tax deductions. As of March 31, 2018, there is no liability for unrecognized income tax benefits. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. We continue to voluntarily participate in the Internal Revenue Service's ("IRS") Compliance Assurance Program for the 2017 and 2018 tax years. We have received final acceptance of our 2016 federal income tax return from the IRS; however, this return is going through the Joint Tax Committee review process due to tax refunds requested. |
Asset Retirement Obligations |
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Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation Disclosure | 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:
Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging and abandonment costs 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. As of March 31, 2018, the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 6.5 percent to 7.5 percent. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors, and changes to our credit-adjusted risk-free rate as market conditions warrant. Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets. |
Commitments and Contingencies |
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Commitments and Contingencies Disclosure | COMMITMENTS AND CONTINGENCIES Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties, and produced by our affiliated partnerships and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. Our condensed consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. The following table presents gross volume information related to our long-term firm transportation and processing agreements for pipeline capacity:
In March 2018, we completed the sale of our Utica Shale properties. Upon closing, the related commitment was assumed by the purchaser of the Utica Shale properties. In anticipation of our future drilling activities in the Wattenberg Field, we have entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct two new 200 MMcfd cryogenic plants. We will be bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service dates of the plants, which, as reflected in the above table, are currently scheduled to be in the third quarter of 2018 for the first plant and the second quarter of 2019 for the second plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016, to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. Any shortfall in these volume commitments may be offset by other producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. We currently expect that our future development plans will meet both the baseline and incremental volumes, and we believe that the contractual target profit margin will be achieved without additional payment from us. In April 2018, we entered into a five-year firm transportation agreement, effective May 1, 2018, with a third-party crude oil pipeline company to transport 12,500 barrels of crude oil per day from our Wattenberg Field via pipeline to Cushing, Oklahoma and other area refineries. This agreement is reflected in the pipeline capacity commitment table above. In May 2018, we entered into a firm sales agreement that is effective from June 1, 2018 through December 31, 2023 for an initial 11,400 barrels of crude oil per day and incrementally increasing to 26,400 barrels of crude oil per day with a large integrated marketing company for our crude oil production in the Delaware Basin. This agreement is expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. The fixed transportation charge associated with this agreement is reflected in the pipeline capacity commitment table above. For the three months ended March 31, 2018, commitments for long-term transportation volumes, net to our interest, for Wattenberg Field crude oil and Delaware Basin natural gas were $2.6 million, and in accordance with the guidance in the new revenue recognition standard, were netted against our crude oil and natural gas sales in our condensed consolidated statements of operations. For the three months ended March 31, 2017, commitments for long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $2.2 million and were recorded in transportation, gathering, and processing expense in our condensed consolidated statements of operations. Litigation and Legal Items. We are involved in various legal proceedings. We review 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 our best interests. We have provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations, or liquidity. Action Regarding Partnerships. In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al., filed in the United States District Court for the District of Colorado. The complaint states that it is a derivative action brought by a number of limited partner investors seeking to assert claims on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP, against PDC and includes claims for breach of fiduciary duty and breach of contract. The plaintiffs also included claims against two of our senior officers for alleged breach of fiduciary duty. The lawsuit accuses PDC, as the managing general partner of the two partnerships, of, among other things, failing to maximize the productivity of the partnerships’ crude oil and natural gas wells. We filed a motion to dismiss the lawsuit on February 1, 2018, on the grounds that the complaint is deficient, including because the plaintiffs failed to allege that PDC refused a demand to take action on their claims. On March 14, 2018, the motion was denied as moot by the court because the plaintiffs requested leave to amend their complaint. In late April 2018, the plaintiffs filed an amendment to their complaint. Such amendment primarily alleges additional facts to support the plaintiffs’ claims and purports to add direct class action claims in addition to the original derivative claims. The amendment also adds three new individual defendants, all of which are independent members of our Board of Directors. We are currently unable to estimate any potential damages as a result of this lawsuit. Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of March 31, 2018 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 potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual. Clean Air Act Tentative Agreement and Related Consent Decree. In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado ("DJ Basin"). The Information Request focused on historical operation and design information for 46 of our production facilities and requested sampling and analyses at the identified 46 facilities. We responded to the Information Request with the requested data in January 2016. In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. In June 2017, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects) of which the cash fines were paid in the first quarter of 2018 and the environmental projects have been accrued in other accrued expenses on our consolidated balance sheet as of March 31, 2018 (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations; and (iii) mitigation with an estimated cost of $1.7 million. We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. In addition, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. Since our entry into the consent decree we have implemented a comprehensive program to comply with all of its requirements. As of the date of the filing of this report, all aspects of the consent decree compliance program are on or ahead of schedule. |
Common Stock |
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Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award | COMMON STOCK 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:
Stock Appreciation Rights The stock appreciation right ("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. No SARs were awarded or expired during the three months ended March 31, 2018. Total compensation cost related to non-vested SARs granted and not yet recognized in our condensed consolidated statement of operations as of March 31, 2018 was $1.4 million. The cost is expected to be recognized over a weighted-average period of 1.52 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. The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the three months ended March 31, 2018:
The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:
Total compensation cost related to non-vested time-based awards and not yet recognized in our condensed consolidated statements of operations as of March 31, 2018 was $20.6 million. This cost is expected to be recognized over a weighted-average period of 2.0 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. The Compensation Committee of our Board of Directors awarded a total of 90,778 market-based restricted shares to our executive officers during the three months ended March 31, 2018. In addition to continuous employment, the vesting of these shares is contingent on our total stockholder return ("TSR"), which is essentially our 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, 2020, and can result in a payout between 0 percent and 200 percent of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards was computed using the Monte Carlo pricing model using the following assumptions:
The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. The following table presents the change in non-vested market-based awards during the three months ended March 31, 2018:
The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:
Total compensation cost related to non-vested market-based awards not yet recognized in our condensed consolidated statements of operations as of March 31, 2018 was $7.9 million. This cost is expected to be recognized over a weighted-average period of 2.5 years. Preferred Stock We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges, and restrictions as shall be fixed by our Board of Directors from time to time. Through March 31, 2018, no preferred shares have been issued. |
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Earnings Per Share | 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:
We reported a net loss for the three months ended March 31, 2018. As a result, our basic and diluted weighted-average common shares outstanding were the same for that period because the effect of the common share equivalents was anti-dilutive. The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect:
In September 2016, we issued the 2021 Convertible Notes, which give the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $85.39 conversion price during the periods presented. During the three months ended March 31, 2018 and 2017, the average market price of our common stock did not exceed the conversion price; therefore, shares issuable upon conversion of the 2021 Convertible Notes were not included in the diluted earnings per share calculation. |
Subsidiary Guarantor Subsidiary Guarantor (Notes) |
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Guarantees [Text Block] | SUBSIDIARY GUARANTOR PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the condensed consolidating financial information separately for:
The Guarantor is 100 percent owned by the Parent. The senior notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the condensed consolidating financial information follows the same accounting policies as described in the notes to the condensed consolidated financial statements. The following condensed consolidating financial statements have been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column.
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Significant Accounting Policies (Policies) |
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Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block] | On January 1, 2018, we adopted the new accounting standard that was issued by the FASB and the International Accounting Standards Board that converged their standard on revenue recognition and provides a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all the related amendments (“new revenue standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the standard would have reduced our crude oil, natural gas, and NGLs sales by approximately $2.5 million in the first quarter of 2017 with a corresponding decrease in transportation, gathering, and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas, and NGLs sales and our transportation, processing, and gathering expenses for the three months ended March 31, 2017, we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the new standard to have a significant impact on our net income going forward. Crude oil, natural gas, and NGLs revenues are recognized when we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits, from the crude oil, natural gas, or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas, and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the three months ended March 31, 2018 and 2017 the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. Our crude oil, natural gas, and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas, or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering, or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas, or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering, and processing expenses. Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the new revenue recognition standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the new revenue standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the new revenue standard will be recognized using the net-back method. As discussed above, we enter into agreements for the sale, transportation, gathering, and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and our natural gas average NYMEX pricing is based upon first-of-the-month index prices as this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. |
Revenue Recognition, Customer Acquisitions [Policy Text Block] | Contract Assets. Contract assets include material contributions in aid of construction ("CIAC"), which are common in purchase/purchase and processing agreements with midstream service providers that are our customers. Generally, the intent of the payments is to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets that are classified as current assets are included in prepaid expenses and other current assets on our condensed consolidated balance sheet. Contract assets that are classified as long-term are included in other assets on our condensed consolidated balance sheet. The contract assets will be amortized as a reduction to crude oil, natural gas, or NGLs sales revenue during the periods that the related production is transferred to the customer. |
Consolidation, Policy | The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues, and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation |
Basis of Accounting, Policy | In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2017 condensed consolidated balance sheet data was derived from audited statements, but does not include all disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2017 Form 10-K. Our results of operations and cash flows for the three months ended March 31, 2018 are not necessarily indicative of the results to be expected for the full year or any other future period |
Recently Issued Accounting Policy [Policy Text Block] | In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. The standard has been updated and now includes amendments. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our condensed consolidated financial statements. |
Earnings Per Share, Policy | 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. |
Summary of Significant Accounting Policies Cash, Cash Equivalents, and Restricted Cash (Tables) |
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Schedule of Cash and Cash Equivalents [Table Text Block] | The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the condensed consolidated balance sheets at March 31, 2018 and December 31, 2017, which sum to the total of cash, cash equivalents, and restricted cash in the condensed consolidated statements of cash flows:
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Business Combination Business Combinations (Tables) |
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Business Combination, Segment Allocation [Table Text Block] | The details of the estimated purchase price and the preliminary allocation of the purchase price for the transaction, are presented below (in thousands):
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Revenue Recognition (Tables) |
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Capitalized Contract Cost [Table Text Block] | The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas, and NGLs sales revenue for the three months ended March 31, 2018:
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Disaggregation of Revenue [Table Text Block] | Disaggregated Revenue. The following table presents crude oil, natural gas, and NGLs sales disaggregated by commodity and operating region for the three months ended March 31, 2018 and 2017 (in thousands):
________________ (1) In March 2018, we completed the sale of our Utica Shale properties. (2) As we have elected the modified retrospective method of adoption, revenues for the three months ended March 31, 2017 have not been restated for the new revenue recognition standard. Such amounts would not have been material. |
Fair Value Measurements and Disclosures (Tables) |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and 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:
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Fair Value Assets and Liabilities Unobservable Input Reconciliation | The following table presents a reconciliation of our Level 3 assets measured at fair value:
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Fair Value Measurements and Disclosures Fair value of the portion of long-term debt related to senior and convertible notes (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block] | 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, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of March 31, 2018.
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Derivative Financial Instruments (Tables) |
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Derivative [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block] | As of March 31, 2018, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
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Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location [Table Text Block] | The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets:
The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:
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Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets:
The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:
Net settlements of commodity derivatives and net change in fair value of unsettled derivatives decreased for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017 as a result of the increase in future commodity prices during the first quarter of 2018 compared to a decrease during the first quarter of 2017. 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. 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:
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Properties and Equipment (Tables) |
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil and Gas Property [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment | The following table presents the components of properties and equipment, net of accumulated depreciation, depletion, and amortization ("DD&A"):
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Impairment of natural gas and crude oil properties | The following table presents impairment charges recorded for crude oil and natural gas properties:
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Disclosure of Long Lived Assets Held-for-sale [Table Text Block] | The following table presents balance sheet data related to assets held-for-sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities that are expected to be assumed by the purchasers:
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Schedule of Aging of Capitalized Exploratory Well Costs [Table Text Block] | The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the condensed consolidated balance sheets:
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Other Accrued Expenses Other Accrued Expenses (Tables) |
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Accrued Expense, Current [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Current [Text Block] | The following table presents the components of other accrued expenses as of:
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Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Noncurrent [Text Block] | The following table presents the components of other liabilities as of:
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Long-Term Debt (Tables) |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Long-term Debt Instruments | Long-term debt consisted of the following as of:
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Capital Leases (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capital Leases [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Capital Leased Assets [Table Text Block] | The following table presents vehicles under capital lease as of:
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Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block] | 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:
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Asset Retirement Obligations (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Change in Asset Retirement Obligation | 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:
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Commitments and Contingencies Commitments and Contigencies (Tables) |
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Commitments and Contingencies Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supply Commitment | :
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Common Stock (Tables) |
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Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan | 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:
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Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the three months ended March 31, 2018:
The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:
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Restricted Stock Awards, Market-Based, Valuation assumptions | he Compensation Committee of our Board of Directors awarded a total of 90,778 market-based restricted shares to our executive officers during the three months ended March 31, 2018. In addition to continuous employment, the vesting of these shares is contingent on our total stockholder return ("TSR"), which is essentially our 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, 2020, and can result in a payout between 0 percent and 200 percent of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards was computed using the Monte Carlo pricing model using the following assumptions:
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Schedule of Nonvested Performance-based Units Activity | The following table presents the change in non-vested market-based awards during the three months ended March 31, 2018:
The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:
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Earnings Per Share (Tables) |
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Earnings Per Share Reconciliation | The following table presents a reconciliation of the weighted-average diluted shares outstanding:
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Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share | 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:
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Subsidiary Guarantor Subsidiary Guarantor (Tables) |
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Subsidiary Guarantor [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Guarantor Obligations [Table Text Block] | The following condensed consolidating financial statements have been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column.
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Nature of Operations and Basis of Presentation Additional Information (Details) |
3 Months Ended |
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Mar. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Oil and gas producing wells, gross | 3,000 |
Number of Operating Segments | 2 |
Summary of Significant Accounting Policies Reconciliation of cash, cash equivalents, and restricted cash (Details) - USD ($) $ in Thousands |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | ||
Cash and cash equivalents | $ 45,923 | $ 180,675 |
Restricted Cash | 8,001 | 9,250 |
Restricted Cash and Cash Equivalents | $ 53,924 | $ 189,925 |
Revenue Recognition Contract Assets (Details) - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Dec. 31, 2017 |
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Revenue from Contract with Customer [Abstract] | ||
Capitalized Contract Cost, Gross | $ 3,213 | $ 4,446 |
Capitalized Contract Cost, Amortization | $ (1,233) |
Revenue Recognition Accounts Receivable (Details) - USD ($) $ in Millions |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Revenue from Contract with Customer [Abstract] | ||
Accounts Receivable, Gross | $ 145.3 | $ 154.3 |
Revenue Recognition Revenue, Initial Application Period Cumulative Effect Transition (Details) $ in Millions |
3 Months Ended |
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Mar. 31, 2017
USD ($)
| |
Revenue from Contract with Customer [Abstract] | |
Revenue, Initial Application Period Cumulative Effect Transition, Explanation of Change | $ 2.5 |
Fair Value Measurements and Disclosures (Details) - Fair Value - USD ($) $ in Thousands |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Assets and Liabilities at Fair Value | ||
Total assets | $ 28,610 | $ 14,338 |
Total liabilities | 137,109 | 101,645 |
Net asset (fair value) | (108,499) | (87,307) |
Significant Other Observable Inputs (Level 2) | ||
Assets and Liabilities at Fair Value | ||
Total assets | 22,467 | 12,949 |
Total liabilities | 122,133 | 90,569 |
Net asset (fair value) | (99,666) | (77,620) |
Significant Unobservable Inputs (Level 3) | ||
Assets and Liabilities at Fair Value | ||
Total assets | 6,143 | 1,389 |
Total liabilities | 14,976 | 11,076 |
Net asset (fair value) | $ (8,833) | $ (9,687) |
Reconciliation of Level 3 Fair Value Measurements (Details) - Derivative Financial Instrument Net Assets - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
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Roll-forward of Level 3 Assets | ||
Fair Value, net assets, beginning of period | $ (9,687) | $ (9,574) |
Fair Value, net assets, end of period | (8,833) | 2,316 |
Commodity Price Risk Management (loss), net | ||
Roll-forward of Level 3 Assets | ||
Changes in fair value included in statement of operations line item: | (2,152) | 13,360 |
Settlements included in statement of operations line items: | 3,006 | (1,470) |
Net change in fair value of unsettled derivatives included in statement of operations line item | $ 1,205 | $ 11,427 |
Fair Value Measurements and Disclosures Notes Receivable (Details) $ in Millions |
Mar. 31, 2018
USD ($)
|
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1.125% Convertible Senior Notes due 2021 [Member] | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Notes Payable, Fair Value Disclosure | $ 194.0 |
Senior Notes fair value | 97.00% |
5.75% Senior Notes due 2026 [Member] | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Notes Payable, Fair Value Disclosure | $ 593.3 |
Senior Notes fair value | 98.90% |
6.125% Senior Notes due 2024 [Member] | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Notes Payable, Fair Value Disclosure | $ 409.0 |
Senior Notes fair value | 102.30% |
Impact of Derivative Instruments on Statement of Operations (Details) - Commodity Price Risk Management (loss), net - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
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Derivative [Line Items] | ||
Net settlements | $ (26,038) | $ 551 |
Net change in fair value of unsettled derivatives | (21,202) | 80,153 |
Total commodity price risk management gain (loss), net | $ (47,240) | $ 80,704 |
Derivative Financial Instruments Impact of Netting Agreements (Details) - USD ($) $ in Thousands |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Derivative Asset: | ||
Derivative assets, gross | $ 28,610 | $ 14,338 |
Effect of master netting agreements | (27,971) | (14,173) |
Derivative asset, net | 639 | 165 |
Derivative Liability: | ||
Derivative liability, gross | 137,109 | 101,645 |
Effect of master netting agreements | (27,971) | (14,173) |
Derivative liability, net | $ 109,138 | $ 87,472 |
Properties and Equipment (Details) $ in Thousands |
3 Months Ended | 12 Months Ended | |
---|---|---|---|
Mar. 31, 2018
USD ($)
Wells
|
Dec. 31, 2017
USD ($)
Wells
|
Dec. 31, 2016
USD ($)
|
|
Property, Plant and Equipment [Line Items] | |||
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves | $ 17,143 | $ 51,776 | |
Proved Natural Gas and Crude Oil Properties | 4,706,258 | 4,356,922 | |
Unproved Natural Gas and Crude Oil Properties | 1,055,774 | 1,097,317 | |
Total Natural Gas and Crude Oil Properties | 5,762,032 | 5,454,239 | |
Equipment and other | 125,529 | 109,359 | |
Land and Buildings | 12,679 | 10,960 | |
Construction in Progress | 294,311 | 196,024 | |
Properties and equipment, at cost | 6,194,551 | 5,770,582 | |
Accumulated DD&A | (1,963,294) | (1,837,115) | |
Property, Plant and Equipment, Net | 4,231,257 | 3,933,467 | |
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves | 0 | (36,328) | |
Capitalized Exploratory Well Costs | $ 32,591 | $ 15,448 | $ 0 |
Wells to be completed | Wells | 3 | 3 |
Impairment of Natural Gas and Crude Oil Properties (Details) - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Impairment of natural gas and crude oil properties [Line Items] | ||
Impairment of Leasehold | $ 33,130 | $ 2,102 |
Delaware Basin Unproved Property Impairment | 6,300 | |
Impairment of proved ad unproved properties | 26,900 | |
Amortization of Individually Insignificant Unproved Properties | 58 | 91 |
Impairment of Oil and Gas Properties | 33,188 | 2,193 |
Impairment of properties and equipment | $ 33,188 | $ 2,193 |
Other Accrued Expenses Other Accrued Expenses (Details) - USD ($) $ in Thousands |
3 Months Ended | 12 Months Ended | |
---|---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
Dec. 31, 2017 |
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Schedule of Other Liabilities [Line Items] | |||
Saddle Butte Rockies Midstream Amendment Payment | $ 24,100 | ||
Production Tax Liability | 63,454 | $ 50,476 | |
Other Accrued Liabilities, Noncurrent | 94,557 | 57,333 | |
Accrued Employee Benefits, Current | 10,901 | 22,383 | |
Asset Retirement Obligation, Current | 15,944 | 15,801 | |
Accrued Environmental Loss Contingencies, Current | 2,074 | 1,374 | |
Gas Gathering, Transportation, Marketing and Processing Costs | (7,313) | $ (5,902) | |
Amortization of Other Deferred Charges | 400 | ||
Non Current Liabilities | |||
Schedule of Other Liabilities [Line Items] | |||
Gas Gathering, Transportation, Marketing and Processing Costs | 21,608 | 0 | |
Other Accrued Liabilities | 9,495 | 6,857 | |
Current Liabilities | |||
Schedule of Other Liabilities [Line Items] | |||
Gas Gathering, Transportation, Marketing and Processing Costs | 2,010 | 0 | |
Other Accrued Liabilities | $ 2,848 | $ 3,429 |
Other Accrued Expenses Schedule of Other Accrued Expense (Details) - USD ($) $ in Thousands |
3 Months Ended | 12 Months Ended | |
---|---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
Dec. 31, 2017 |
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Schedule of Other Accrued Expense [Line Items] | |||
Accrued Employee Benefits, Current | $ 10,901 | $ 22,383 | |
Asset Retirement Obligation, Current | 15,944 | 15,801 | |
Accrued Environmental Loss Contingencies, Current | 2,074 | 1,374 | |
Transportation, gathering, and processing expenses | 7,313 | $ 5,902 | |
Other accrued expenses | 33,777 | 42,987 | |
Current Liabilities | |||
Schedule of Other Accrued Expense [Line Items] | |||
Transportation, gathering, and processing expenses | (2,010) | 0 | |
Other Accrued Liabilities | 2,848 | 3,429 | |
Non Current Liabilities | |||
Schedule of Other Accrued Expense [Line Items] | |||
Transportation, gathering, and processing expenses | (21,608) | 0 | |
Other Accrued Liabilities | $ 9,495 | $ 6,857 |
Capital Leases Capital Leases (Details) - USD ($) $ in Thousands |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Capital Leased Assets [Line Items] | ||
Vehicles | $ 6,500 | $ 6,249 |
Accumulated Depreciation | (2,271) | (1,882) |
Capital Leased Assets, Net | $ 4,229 | $ 4,367 |
Capital Leases Minimum Lease Payments (Details) $ in Thousands |
Mar. 31, 2018
USD ($)
|
---|---|
Capital Leased Assets [Line Items] | |
Future Minimum Payments | $ 5,260 |
Executory Costs | (400) |
Amount representing interest | (501) |
Present Value of Net Minimum Payments | 4,359 |
Short-term Capital Lease Obligations | 1,789 |
Long-Term Capital Lease Obligations | 2,570 |
Total Capital Lease Obligations | 4,359 |
2019 | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | 1,952 |
2020 | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | 2,061 |
2021 | |
Capital Leased Assets [Line Items] | |
Future Minimum Payments | $ 1,247 |
Income Taxes (Details) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Income Tax Disclosure [Abstract] | ||
Effective Income Tax Rate, Continuing Operations | 25.80% | 36.30% |
Other Tax Expense (Benefit) | $ 0.2 | |
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | 1.20% |
Asset Retirement Obligations (Details) - USD ($) $ in Thousands |
3 Months Ended | ||
---|---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
Dec. 31, 2017 |
|
Asset Retirement Obligation, Roll Forward Analysis | |||
Balance at beginning of period | $ 87,306 | ||
Obligations incurred with development activities | 620 | ||
Business Acquisition Purchase Price Allocation Asset Retirement Obligation | 4,687 | ||
Accretion expense | 1,288 | $ 1,768 | |
Asset Retirement Obligation, Revision of Estimate | 50 | ||
Obligations discharged asset retirements | (4,102) | ||
Balance end of period | 89,849 | ||
Less current portion | (15,944) | $ (15,801) | |
Asset retirement obligations | $ 73,905 | $ 71,006 | |
Minimum [Member] | |||
Reconciliation Of Changes In Asset Retirement Obligations [Line Items] | |||
Credit Adjusted Risk-Free Rate used to discount plugging and abandonment liabilities range | 6.50% | ||
Maximum [Member] | |||
Reconciliation Of Changes In Asset Retirement Obligations [Line Items] | |||
Credit Adjusted Risk-Free Rate used to discount plugging and abandonment liabilities range | 7.50% |
Commitments and Contingencies Additional information (Details) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018
USD ($)
MMcf
|
Mar. 31, 2017
USD ($)
|
|
Loss Contingencies [Line Items] | ||
Transportation, gathering, and processing expenses | $ 7,313 | $ 5,902 |
First facilities agreement with midstream provider [Member] | ||
Loss Contingencies [Line Items] | ||
incremental volume commitment | MMcf | 51.5 | |
Utica Shale natural gas and Wattenberg Field crude oil [Member] | ||
Loss Contingencies [Line Items] | ||
Transportation, gathering, and processing expenses | $ 2,600 | $ 2,200 |
Commitments and Contingencies New Plant (Details) |
3 Months Ended |
---|---|
Mar. 31, 2018 | |
New Plants [Member] | |
Property, Plant and Equipment [Line Items] | |
Qualitative and Quantitative Information, Transferor's Continuing Involvement, Third Party Commitments | two |
Natural Gas [Member] | |
Property, Plant and Equipment [Line Items] | |
Qualitative and Quantitative Information, Transferor's Continuing Involvement, Third Party Commitments | 200 |
Commitments and Contingencies Clean Air Act (Details) $ in Millions |
3 Months Ended |
---|---|
Mar. 31, 2018
USD ($)
| |
Obligation with Joint and Several Liability Arrangement [Line Items] | |
Supplemental environmental legal expense paid | $ 1.5 |
Supplemental environment projects legal expense | 1.0 |
Injunctive relief legal expense accrual | 18.0 |
Mitigation legal expense accrual | $ 1.7 |
Common Stock Sale of Common Stock (Details) - USD ($) $ / shares in Units, $ in Thousands |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Class of Stock [Line Items] | ||
Common stock, par value | $ 0.01 | $ 0.01 |
Common shares - par value | $ 660 | $ 659 |
Additional paid-in capital | $ 2,504,663 | $ 2,503,294 |
Debt Instrument, Convertible, Conversion Price | $ 85.39 |
Share Based Compensation Summary (Details) - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Employee Service Share-based Compensation, Allocation of Recognized Period Costs | ||
Stock-based compensation expense | $ 5,261 | $ 4,453 |
Income tax benefit | (1,261) | (1,666) |
Net stock-based compensation expense | $ 4,000 | $ 2,787 |
Schedule of Changes in SARs (Details) - Stock Appreciation Rights (SARs) $ in Millions |
3 Months Ended |
---|---|
Mar. 31, 2018
USD ($)
| |
Share based compesation aggregate intrinsic value | |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 1.4 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 6 months 7 days |
Restricted Stock - Market Based Awards Fair Value Assumptions (Details) - Restricted Stock - Market Based Awards - $ / shares |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Share-based Compensation Arrangement by Share-based Payment Award | ||
Expected term of award | 3 years | 3 years |
Risk-free interest rate | 2.40% | 1.40% |
Expected Volatility | 42.30% | 51.40% |
Granted | $ 69.98 | $ 94.02 |
Common Stock Preferred Stock (Details) - shares |
Mar. 31, 2018 |
Dec. 31, 2017 |
Jun. 23, 2008 |
---|---|---|---|
Share-based Compensation Arrangement by Share-based Payment Award | |||
Preferred Stock, Shares Authorized | 50,000,000 | 50,000,000 | |
Preferred Stock, Shares Issued | 0 | 0 | |
Preferred Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Preferred Stock, Shares Authorized | 50,000,000 | ||
Preferred Stock, Shares Issued | 0 |
Common Stock Treasury Shares (Details) - shares |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Share-based Compensation Arrangement by Share-based Payment Award | ||
Common stock, shares authorized | 150,000,000 | 150,000,000 |
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