Delaware | 73-1283193 |
(State or other jurisdiction of incorporation) | (I.R.S. Employer Identification No.) |
7130 South Lewis, Suite 1000, Tulsa, Oklahoma | 74136 |
(Address of principal executive offices) | (Zip Code) |
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Item 4. | ||
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Item 2. | ||
Item 3. | ||
Item 4. | ||
Item 5. | ||
Item 6. | ||
• | the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures; |
• | the number of wells we plan to drill or rework; |
• | prices for oil, NGLs, and natural gas; |
• | demand for oil, NGLs, and natural gas; |
• | our exploration and drilling prospects; |
• | the estimates of our proved oil, NGLs, and natural gas reserves; |
• | oil, NGLs, and natural gas reserve potential; |
• | development and infill drilling potential; |
• | expansion and other development trends of the oil and natural gas industry; |
• | our business strategy; |
• | our plans to maintain or increase production of oil, NGLs, and natural gas; |
• | the number of gathering systems and processing plants we plan to construct or acquire; |
• | volumes and prices for natural gas gathered and processed; |
• | expansion and growth of our business and operations; |
• | demand for our drilling rigs and drilling rig rates; |
• | our belief that the final outcome of our legal proceedings will not materially affect our financial results; |
• | our ability to timely secure third-party services used in completing our wells; |
• | our ability to transport or convey our oil or natural gas production to established pipeline systems; |
• | impact of federal and state legislative and regulatory actions impacting our costs and increasing operating restrictions or delays as well as other adverse impacts on our business; |
• | our projected production guidelines for the year; |
• | our anticipated capital budgets; and |
• | the number of wells our oil and natural gas segment plans to drill during the year. |
• | the risk factors discussed in this document and in the documents we incorporate by reference; |
• | general economic, market, or business conditions; |
• | the availability of and nature of (or lack of) business opportunities that we pursue; |
• | demand for our land drilling services; |
• | changes in laws or regulations; |
• | decreases or increases in commodity prices; and |
• | other factors, most of which are beyond our control. |
June 30, 2013 | December 31, 2012 | ||||||
(In thousands except share amounts) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 1,041 | $ | 974 | |||
Accounts receivable, net of allowance for doubtful accounts of $5,342 and $5,343 at June 30, 2013 and at December 31, 2012, respectively | 156,706 | 146,046 | |||||
Materials and supplies | 9,314 | 8,563 | |||||
Current derivative asset (Note 9) | 9,895 | 16,552 | |||||
Current income tax receivable | 3,348 | 901 | |||||
Current deferred tax asset | 8,980 | 8,765 | |||||
Prepaid expenses and other | 10,385 | 13,843 | |||||
Total current assets | 199,669 | 195,644 | |||||
Property and equipment: | |||||||
Oil and natural gas properties on the full cost method: | |||||||
Proved properties | 4,015,975 | 3,822,381 | |||||
Undeveloped leasehold not being amortized | 543,535 | 521,659 | |||||
Drilling equipment | 1,487,769 | 1,478,645 | |||||
Gas gathering and processing equipment | 511,896 | 461,629 | |||||
Transportation equipment | 39,076 | 37,728 | |||||
Other | 70,065 | 62,840 | |||||
6,668,316 | 6,384,882 | ||||||
Less accumulated depreciation, depletion, amortization, and impairment | 3,061,990 | 2,907,660 | |||||
Net property and equipment | 3,606,326 | 3,477,222 | |||||
Debt issuance cost | 12,638 | 13,432 | |||||
Goodwill | 62,808 | 62,808 | |||||
Other intangible assets, net | 171 | 680 | |||||
Non-current derivative asset (Note 9) | 4,887 | — | |||||
Other assets | 13,025 | 11,334 | |||||
Total assets | $ | 3,899,524 | $ | 3,761,120 |
June 30, 2013 | December 31, 2012 | ||||||
(In thousands except share amounts) | |||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 118,084 | $ | 138,811 | |||
Accrued liabilities (Note 4) | 58,832 | 54,098 | |||||
Current portion of derivative liabilities (Note 9) | 879 | 1,948 | |||||
Current portion of other long-term liabilities (Note 5) | 12,136 | 12,282 | |||||
Total current liabilities | 189,931 | 207,139 | |||||
Long-term debt (Note 5) | 715,474 | 716,359 | |||||
Non-current derivative liabilities (Note 9) | — | 562 | |||||
Other long-term liabilities (Note 5) | 160,907 | 166,983 | |||||
Deferred income taxes | 753,663 | 695,776 | |||||
Shareholders’ equity: | |||||||
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued | — | — | |||||
Common stock, $.20 par value, 175,000,000 shares authorized, 49,105,600 and 48,581,948 shares issued, respectively | 9,643 | 9,594 | |||||
Capital in excess of par value | 435,467 | 423,603 | |||||
Accumulated other comprehensive income (Note 11) | 1,709 | 7,587 | |||||
Retained earnings | 1,632,730 | 1,533,517 | |||||
Total shareholders’ equity | 2,079,549 | 1,974,301 | |||||
Total liabilities and shareholders’ equity | $ | 3,899,524 | $ | 3,761,120 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands except per share amounts) | |||||||||||||||
Revenues: | |||||||||||||||
Oil and natural gas | $ | 164,799 | $ | 131,166 | $ | 318,408 | $ | 266,931 | |||||||
Contract drilling | 105,005 | 146,872 | 212,533 | 287,778 | |||||||||||
Gas gathering and processing | 70,617 | 49,747 | 128,012 | 107,042 | |||||||||||
Total revenues | 340,421 | 327,785 | 658,953 | 661,751 | |||||||||||
Expenses: | |||||||||||||||
Oil and natural gas: | |||||||||||||||
Operating costs | 44,994 | 33,279 | 88,032 | 68,888 | |||||||||||
Depreciation, depletion, and amortization | 55,335 | 57,153 | 107,318 | 109,350 | |||||||||||
Impairment of oil and natural gas properties (Note 2) | — | 115,874 | — | 115,874 | |||||||||||
Contract drilling: | |||||||||||||||
Operating costs | 63,590 | 74,819 | 129,592 | 150,992 | |||||||||||
Depreciation | 17,908 | 21,238 | 35,168 | 42,566 | |||||||||||
Gas gathering and processing: | |||||||||||||||
Operating costs | 59,557 | 42,363 | 108,967 | 89,976 | |||||||||||
Depreciation and amortization | 8,214 | 5,312 | 15,370 | 10,446 | |||||||||||
General and administrative | 9,679 | 8,376 | 18,352 | 15,380 | |||||||||||
Gain on disposition of assets | (3,483 | ) | (651 | ) | (3,399 | ) | (1,239 | ) | |||||||
Total operating expenses | 255,794 | 357,763 | 499,400 | 602,233 | |||||||||||
Income (loss) from operations | 84,627 | (29,978 | ) | 159,553 | 59,518 | ||||||||||
Other income (expense): | |||||||||||||||
Interest, net | (4,591 | ) | (2,542 | ) | (8,152 | ) | (4,368 | ) | |||||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | 16,344 | 1,387 | 10,420 | (606 | ) | ||||||||||
Other | (91 | ) | 69 | (157 | ) | (64 | ) | ||||||||
Total other income (expense) | 11,662 | (1,086 | ) | 2,111 | (5,038 | ) | |||||||||
Income (loss) before income taxes | 96,289 | (31,064 | ) | 161,664 | 54,480 | ||||||||||
Income tax expense (benefit): | |||||||||||||||
Current | 2,117 | (2,066 | ) | 4,634 | (2,066 | ) | |||||||||
Deferred | 35,165 | (9,696 | ) | 57,817 | 23,409 | ||||||||||
Total income taxes | 37,282 | (11,762 | ) | 62,451 | 21,343 | ||||||||||
Net income (loss) | $ | 59,007 | $ | (19,302 | ) | $ | 99,213 | $ | 33,137 | ||||||
Net income (loss) per common share: | |||||||||||||||
Basic | $ | 1.22 | $ | (0.40 | ) | $ | 2.06 | $ | 0.69 | ||||||
Diluted | $ | 1.22 | $ | (0.40 | ) | $ | 2.05 | $ | 0.69 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands) | |||||||||||||||
Net income (loss) | $ | 59,007 | $ | (19,302 | ) | $ | 99,213 | $ | 33,137 | ||||||
Other comprehensive income (loss), net of taxes: | |||||||||||||||
Change in value of derivative instruments used as cash flow hedges, net of tax of $3,874, $17,256, ($2,504), and $16,214 | 6,091 | 27,226 | (3,820 | ) | 25,490 | ||||||||||
Reclassification - derivative settlements, net of tax of $317, ($6,106), ($1,177), and ($9,270) | 506 | (9,564 | ) | (1,831 | ) | (14,576 | ) | ||||||||
Ineffective portion of derivatives, net of tax of ($667), ($537), ($141), and $232 | (1,050 | ) | (850 | ) | (227 | ) | 374 | ||||||||
Comprehensive income (loss) | $ | 64,554 | $ | (2,490 | ) | $ | 93,335 | $ | 44,425 |
Six Months Ended June 30, | |||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
OPERATING ACTIVITIES: | |||||||
Net income | $ | 99,213 | $ | 33,137 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, depletion, and amortization | 159,369 | 163,140 | |||||
Impairment of oil and natural gas properties (Note 2) | — | 115,874 | |||||
Unrealized (gain) loss on derivatives | (9,561 | ) | 606 | ||||
Deferred tax expense | 57,817 | 23,409 | |||||
Gain on disposition of assets | (3,399 | ) | (1,239 | ) | |||
Stock compensation plans | 10,654 | 7,978 | |||||
Other, net | 3,005 | 2,218 | |||||
Changes in operating assets and liabilities increasing (decreasing) cash: | |||||||
Accounts receivable | (13,001 | ) | 1,675 | ||||
Accounts payable | 2,219 | (28,587 | ) | ||||
Material and supplies | (751 | ) | (129 | ) | |||
Accrued liabilities | 11,313 | (2,151 | ) | ||||
Other, net | 1,010 | (899 | ) | ||||
Net cash provided by operating activities | 317,888 | 315,032 | |||||
INVESTING ACTIVITIES: | |||||||
Capital expenditures | (339,300 | ) | (371,703 | ) | |||
Producing property and other acquisitions | — | (2,193 | ) | ||||
Proceeds from disposition of assets | 16,829 | 6,288 | |||||
Net cash used in investing activities | (322,471 | ) | (367,608 | ) | |||
FINANCING ACTIVITIES: | |||||||
Borrowings under credit agreement | 183,900 | 250,500 | |||||
Payments under credit agreement | (185,000 | ) | (217,600 | ) | |||
Proceeds from exercise of stock options | 81 | 89 | |||||
Book overdrafts | 5,669 | 19,837 | |||||
Net cash provided by financing activities | 4,650 | 52,826 | |||||
Net increase in cash and cash equivalents | 67 | 250 | |||||
Cash and cash equivalents, beginning of period | 974 | 835 | |||||
Cash and cash equivalents, end of period | $ | 1,041 | $ | 1,085 |
Income (Numerator) | Weighted Shares (Denominator) | Per-Share Amount | ||||||||
(In thousands except per share amounts) | ||||||||||
For the three months ended June 30, 2013 | ||||||||||
Basic earnings per common share | $ | 59,007 | 48,208 | $ | 1.22 | |||||
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs) | — | 298 | — | |||||||
Diluted earnings per common share | $ | 59,007 | 48,506 | $ | 1.22 | |||||
For the three months ended June 30, 2012 | ||||||||||
Basic earnings (loss) per common share | $ | (19,302 | ) | 47,906 | $ | (0.40 | ) | |||
Effect of dilutive stock options, restricted stock, and SARs | — | — | — | |||||||
Diluted earnings (loss) per common share | $ | (19,302 | ) | 47,906 | $ | (0.40 | ) |
Three Months Ended June 30, | |||||||
2013 | 2012 | ||||||
Stock options and SARs | 250,901 | 292,901 | |||||
Average exercise price | $ | 52.72 | $ | 50.99 |
Income (Numerator) | Weighted Shares (Denominator) | Per-Share Amount | ||||||||
(In thousands except per share amounts) | ||||||||||
For the six months ended June 30, 2013 | ||||||||||
Basic earnings per common share | $ | 99,213 | 48,162 | $ | 2.06 | |||||
Effect of dilutive stock options, restricted stock, and SARs | — | 329 | (0.01 | ) | ||||||
Diluted earnings per common share | $ | 99,213 | 48,491 | $ | 2.05 | |||||
For the six months ended June 30, 2012 | ||||||||||
Basic earnings per common share | $ | 33,137 | 47,868 | $ | 0.69 | |||||
Effect of dilutive stock options, restricted stock, and SARs | — | 245 | — | |||||||
Diluted earnings per common share | $ | 33,137 | 48,113 | $ | 0.69 |
Six Months Ended June 30, | |||||||
2013 | 2012 | ||||||
Stock options and SARs | 149,665 | 250,901 | |||||
Average exercise price | $ | 58.41 | $ | 52.72 |
June 30, 2013 | December 31, 2012 | ||||||
(In thousands) | |||||||
Employee costs | $ | 19,269 | $ | 24,632 | |||
Lease operating expenses | 12,612 | 10,903 | |||||
Taxes | 9,507 | 7,308 | |||||
Interest payable | 7,024 | 6,568 | |||||
Other | 10,420 | 4,687 | |||||
Total accrued liabilities | $ | 58,832 | $ | 54,098 |
June 30, 2013 | December 31, 2012 | ||||||
(In thousands) | |||||||
Credit agreement with an average interest rate of 1.9% and 2.9% at June 30, 2013 and December 31, 2012, respectively | $ | 70,000 | $ | 71,100 | |||
6.625% senior subordinated notes due 2021, net of unamortized discount of $4.5 million at June 30, 2013 and $4.7 million at December 31, 2012 | 645,474 | 645,259 | |||||
Total long-term debt | $ | 715,474 | $ | 716,359 |
• | the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% of our consolidated net income for the preceding fiscal year; |
• | the incurrence of additional debt with certain limited exceptions; and |
• | the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our properties, except in favor of our lenders. |
• | a current ratio (as defined in the credit agreement) of not less than 1 to 1; and |
• | a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1. |
June 30, 2013 | December 31, 2012 | ||||||
(In thousands) | |||||||
Asset retirement obligation (ARO) liability | $ | 137,039 | $ | 146,159 | |||
Workers’ compensation | 20,424 | 18,517 | |||||
Separation benefit plans | 8,562 | 7,972 | |||||
Gas balancing liability | 3,838 | 3,838 | |||||
Deferred compensation plan | 3,180 | 2,779 | |||||
173,043 | 179,265 | ||||||
Less current portion | 12,136 | 12,282 | |||||
Total other long-term liabilities | $ | 160,907 | $ | 166,983 |
Six Months Ended June 30, | |||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
ARO liability, January 1: | $ | 146,159 | $ | 96,446 | |||
Accretion of discount | 2,825 | 2,126 | |||||
Liability incurred | 2,869 | 4,420 | |||||
Liability settled | (3,516 | ) | (1,447 | ) | |||
Revision of estimates (1) | (11,298 | ) | (5,022 | ) | |||
ARO liability, June 30: | 137,039 | 96,523 | |||||
Less current portion | 2,948 | 2,909 | |||||
Total long-term ARO | $ | 134,091 | $ | 93,614 |
(1) | Plugging liability estimates were revised in both 2013 and 2012 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Shares granted: | |||||||||||||||
Employees | — | — | 448,549 | 367,936 | |||||||||||
Non employee directors | 21,128 | 24,606 | 21,128 | 24,606 | |||||||||||
21,128 | 24,606 | 469,677 | 392,542 | ||||||||||||
Estimated fair value (in millions): | |||||||||||||||
Employees | $ | — | $ | — | $ | 21.0 | $ | 15.6 | |||||||
Non employee directors | 0.9 | 1.0 | 0.9 | 1.0 | |||||||||||
$ | 0.9 | $ | 1.0 | $ | 21.9 | $ | 16.6 | ||||||||
Percentage of shares granted expected to be distributed: | |||||||||||||||
Employees | N/A | N/A | 94 | % | 89 | % | |||||||||
Non employee directors | 100 | % | 100 | % | 100 | % | 100 | % |
• | Swaps. We receive or pay a fixed price for the hedged commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. |
• | Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. |
Term | Commodity | Hedged Volume | Weighted Average Fixed Price for Swaps | Hedged Market |
Jul’13 – Dec’13 | Crude oil – swap | 5,500 Bbl/day | $99.71 | WTI – NYMEX |
Jul’13 – Dec’13 | Natural gas – swap | 60,000 MMBtu/day | $3.56 | IF – NYMEX (HH) |
Jul’13 – Dec’13 | Natural gas – collar | 20,000 MMBtu/day | $3.25-3.72 | IF – NYMEX (HH) |
Term | Commodity | Hedged Volume | Weighted Average Fixed Price for Swaps | Hedged Market |
Jul’13 – Dec’13 | Crude oil – swap | 3,000 Bbl/day | $94.59 | WTI – NYMEX |
Jan’14 – Dec’14 | Crude oil – swap | 3,000 Bbl/day | $91.77 | WTI – NYMEX |
Jan’14 – Dec’14 | Crude oil – collar | 2,000 Bbl/day | $90.00-95.00 | WTI – NYMEX |
Jul’13 – Dec’13 | Natural gas – swap | 20,000 MMBtu/day | $3.94 | IF – NYMEX (HH) |
Jan’14 – Dec’14 | Natural gas – swap | 50,000 MMBtu/day | $4.24 | IF – NYMEX (HH) |
Term | Commodity | Hedged Volume | Weighted Average Fixed Price for Swaps | Hedged Market |
Jan’14 – Dec’14 | Crude oil – collar | 2,000 Bbl/day | $90.00-97.15 | WTI – NYMEX |
Derivative Assets | ||||||||
Fair Value | ||||||||
Balance Sheet Location | June 30, 2013 | December 31, 2012 | ||||||
(In thousands) | ||||||||
Derivatives designated as hedging instruments | ||||||||
Commodity derivatives: | ||||||||
Current | Current derivative asset | $ | 4,215 | $ | 13,674 | |||
Long-term | Non-current derivative asset | — | — | |||||
Total derivatives designated as hedging instruments | 4,215 | 13,674 |
Derivatives not designated as hedging instruments | ||||||||
Commodity derivatives: | ||||||||
Current | Current derivative asset | $ | 5,680 | $ | 2,878 | |||
Long-term | Non-current derivative asset | 4,887 | — | |||||
Total derivatives not designated as hedging instruments | 10,567 | 2,878 | ||||||
Total derivative assets | $ | 14,782 | $ | 16,552 |
Derivative Liabilities | ||||||||
Fair Value | ||||||||
Balance Sheet Location | June 30, 2013 | December 31, 2012 | ||||||
(In thousands) | ||||||||
Derivatives designated as hedging instruments | ||||||||
Commodity derivatives: | ||||||||
Current | Current derivative liabilities | $ | 879 | $ | 1,005 | |||
Long-term | Non-current derivative liabilities | — | — | |||||
Total derivatives designated as hedging instruments | 879 | 1,005 |
Derivatives not designated as hedging instruments | ||||||||
Commodity derivatives: | ||||||||
Current | Current derivative liabilities | $ | — | $ | 943 | |||
Long-term | Non-current derivative liabilities | — | 562 | |||||
Total derivatives not designated as hedging instruments | — | 1,505 | ||||||
Total derivative liabilities | $ | 879 | $ | 2,510 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands) | |||||||||||||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net: | |||||||||||||||
Realized gains (losses) on derivatives not designated as hedges | $ | (181 | ) | $ | — | $ | 859 | $ | — | ||||||
Unrealized gains on derivatives not designated as hedges | 14,808 | — | 9,193 | — | |||||||||||
Unrealized gains (losses) on ineffectiveness of cash flow hedges | 1,717 | 1,387 | 368 | (606 | ) | ||||||||||
$ | 16,344 | $ | 1,387 | $ | 10,420 | $ | (606 | ) |
Derivatives in Cash Flow Hedging Relationships | Amount of Gain Recognized in Accumulated OCI on Derivative (Effective Portion) (1) | ||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
Commodity derivatives | $ | 1,709 | $ | 30,314 |
Derivative Instrument | Location of Gain or (Loss) Reclassified from Accumulated OCI into Income & Location of Gain or (Loss) Recognized in Income | Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income (1) | Amount of Gain Recognized in Income (2) | |||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
(In thousands) | ||||||||||||||||
Commodity derivatives | Oil and natural gas revenue | $ | (823 | ) | $ | 15,670 | $ | — | $ | — | ||||||
Commodity derivatives | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | — | — | 1,717 | 1,387 | |||||||||||
Total | $ | (823 | ) | $ | 15,670 | $ | 1,717 | $ | 1,387 |
(1) | Effective portion of gain (loss). |
(2) | Ineffective portion of gain (loss). |
Derivatives Not Designated as Hedging Instruments | Location of Gain or (Loss) Recognized in Income on Derivative | Amount of Gain Recognized in Income on Derivative | ||||||
2013 | 2012 | |||||||
(In thousands) | ||||||||
Commodity derivatives | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | $ | 14,627 | $ | — | |||
Total | $ | 14,627 | $ | — |
Derivative Instrument | Location of Gain or (Loss) Reclassified from Accumulated OCI into Income & Location of Gain or (Loss) Recognized in Income | Amount of Gain Reclassified from Accumulated OCI into Income (1) | Amount of Gain or (Loss) Recognized in Income (2) | |||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
(In thousands) | ||||||||||||||||
Commodity derivatives | Oil and natural gas revenue | $ | 3,008 | $ | 23,846 | $ | — | $ | — | |||||||
Commodity derivatives | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | — | — | 368 | (606 | ) | ||||||||||
Total | $ | 3,008 | $ | 23,846 | $ | 368 | $ | (606 | ) |
(1) | Effective portion of gain (loss). |
(2) | Ineffective portion of gain (loss). |
Derivatives Not Designated as Hedging Instruments | Location of Gain or (Loss) Recognized in Income on Derivative | Amount of Gain Recognized in Income on Derivative | ||||||
2013 | 2012 | |||||||
(In thousands) | ||||||||
Commodity derivatives | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | $ | 10,052 | $ | — | |||
Total | $ | 10,052 | $ | — |
• | Level 1 - unadjusted quoted prices in active markets for identical assets and liabilities. |
• | Level 2 - significant observable pricing inputs other than quoted prices included within level 1 that are either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data. |
• | Level 3 - generally unobservable inputs which are developed based on the best information available and may include our own internal data. |
June 30, 2013 | |||||||||||||||||||
Level 2 | Level 3 | Gross Amounts | Effect of Netting | Net Amounts Presented | |||||||||||||||
(In thousands) | |||||||||||||||||||
Financial assets (liabilities): | |||||||||||||||||||
Commodity derivatives: | |||||||||||||||||||
Assets | $ | 15,395 | $ | 1,781 | $ | 17,176 | $ | (2,394 | ) | $ | 14,782 | ||||||||
Liabilities | (2,938 | ) | (335 | ) | (3,273 | ) | 2,394 | (879 | ) | ||||||||||
$ | 12,457 | $ | 1,446 | $ | 13,903 | $ | — | $ | 13,903 |
December 31, 2012 | |||||||||||||||||||
Level 2 | Level 3 | Gross Amounts | Effect of Netting | Net Amounts Presented | |||||||||||||||
(In thousands) | |||||||||||||||||||
Financial assets (liabilities): | |||||||||||||||||||
Commodity derivatives: | |||||||||||||||||||
Assets | $ | 18,555 | $ | — | $ | 18,555 | $ | (2,003 | ) | $ | 16,552 | ||||||||
Liabilities | (3,918 | ) | (595 | ) | (4,513 | ) | 2,003 | (2,510 | ) | ||||||||||
$ | 14,637 | $ | (595 | ) | $ | 14,042 | $ | — | $ | 14,042 |
Commodity Collars | |||||||
For the three months ended June 30, 2013 | For the six months ended June 30, 2013 | ||||||
(In thousands) | |||||||
Beginning of period | $ | (2,536 | ) | $ | (595 | ) | |
Total gains or losses (realized and unrealized): | |||||||
Included in earnings (1) | 3,346 | 1,405 | |||||
Included in other comprehensive income (loss) | — | — | |||||
Settlements | 636 | 636 | |||||
Transfers out of Level 3 into Level 2 | — | — | |||||
End of period | $ | 1,446 | $ | 1,446 | |||
Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period | $ | 3,982 | $ | 2,041 |
(1) | Commodity collars are reported in the Unaudited Condensed Consolidated Statements of Operations in oil and natural gas revenues (for cash flow hedges) and gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net, respectively. |
Commodity Collars | |||||||
For the three months ended June 30, 2012 | For the six months ended June 30, 2012 | ||||||
(In thousands) | |||||||
Beginning of period | $ | 13,912 | $ | 33,615 | |||
Total gains or losses (realized and unrealized): | |||||||
Included in earnings (1) | 5,456 | 16,874 | |||||
Included in other comprehensive income (loss) | (5,687 | ) | (3,576 | ) | |||
Settlements | (5,551 | ) | (16,859 | ) | |||
Transfers out of Level 3 into Level 2 | — | (21,924 | ) | ||||
End of period | $ | 8,130 | $ | 8,130 | |||
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period | $ | (95 | ) | $ | 15 |
(1) | Commodity collars are reported in the Unaudited Condensed Consolidated Statements of Operations in oil and natural gas revenues (for cash flow hedges) and gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net, respectively. |
Commodity (1) | Fair Value | Valuation Technique | Unobservable Input | Range | ||
(In thousands) | ||||||
Oil collars | $ | 1,781 | Discounted cash flow | Forward commodity price curve | ($5.01) - $9.44 | |
Natural gas collar | $ | (335 | ) | Discounted cash flow | Forward commodity price curve | ($0.34) - $0.10 |
(1) | The commodity contracts detailed in this category include non-exchange-traded natural gas and crude oil collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period. |
Net Gains (Losses) on Cash Flow Hedges | |||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
Balance at April 1: | $ | (3,838 | ) | $ | 13,503 | ||
Other comprehensive income before reclassification | 6,091 | 27,226 | |||||
Amounts reclassified from accumulated other comprehensive income | (544 | ) | (10,415 | ) | |||
New current-period other comprehensive income | 5,547 | 16,811 | |||||
Balance at June 30: | $ | 1,709 | $ | 30,314 |
2013 | 2012 | Affected Line Item in the Statement Where Net Income is Presented | |||||||
(In thousands) | |||||||||
Net gains (loss) on cash flow hedges | |||||||||
Commodity derivatives | $ | (823 | ) | $ | 15,670 | Oil and natural gas revenues | |||
Commodity derivatives | 1,717 | 1,387 | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | ||||||
894 | 17,057 | Total before tax | |||||||
(350 | ) | (6,642 | ) | Tax expense | |||||
Total reclassification for the period | $ | 544 | $ | 10,415 | Net of tax |
Net Gains (Losses) on Cash Flow Hedges | |||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
Balance at January 1: | $ | 7,587 | $ | 19,026 | |||
Other comprehensive income before reclassification | (3,820 | ) | 25,490 | ||||
Amounts reclassified from accumulated other comprehensive income | (2,058 | ) | (14,202 | ) | |||
New current-period other comprehensive income | (5,878 | ) | 11,288 | ||||
Balance at June 30: | $ | 1,709 | $ | 30,314 |
2013 | 2012 | Affected Line Item in the Statement Where Net Income is Presented | |||||||
(In thousands) | |||||||||
Net gains (loss) on cash flow hedges | |||||||||
Commodity derivatives | $ | 3,008 | $ | 23,846 | Oil and natural gas revenues | ||||
Commodity derivatives | 368 | (606 | ) | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | |||||
3,376 | 23,240 | Total before tax | |||||||
(1,318 | ) | (9,038 | ) | Tax expense | |||||
Total reclassification for the period | $ | 2,058 | $ | 14,202 | Net of tax |
• | Oil and natural gas, |
• | Contract drilling, and |
• | Mid-stream |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||
Revenues: | ||||||||||||||||||
Oil and natural gas | $ | 164,799 | $ | 131,166 | $ | 318,408 | $ | 266,931 | ||||||||||
Contract drilling | 118,660 | 160,925 | 238,013 | 313,384 | ||||||||||||||
Elimination of inter-segment revenue | (13,655 | ) | (14,053 | ) | (25,480 | ) | (25,606 | ) | ||||||||||
Contract drilling net of inter-segment revenue | 105,005 | 146,872 | 212,533 | 287,778 | ||||||||||||||
Gas gathering and processing | 92,910 | 65,901 | 173,066 | 140,156 | ||||||||||||||
Elimination of inter-segment revenue | (22,293 | ) | (16,154 | ) | (45,054 | ) | (33,114 | ) | ||||||||||
Gas gathering and processing net of inter-segment revenue | 70,617 | 49,747 | 128,012 | 107,042 | ||||||||||||||
Total revenues | $ | 340,421 | $ | 327,785 | $ | 658,953 | $ | 661,751 | ||||||||||
Operating income (loss): | ||||||||||||||||||
Oil and natural gas | $ | 64,470 | $ | (75,140 | ) | (2 | ) | $ | 123,058 | $ | (27,181 | ) | (2 | ) | ||||
Contract drilling | 23,507 | 50,815 | 47,773 | 94,220 | ||||||||||||||
Gas gathering and processing | 2,846 | 2,072 | 3,675 | 6,620 | ||||||||||||||
Total operating income (loss) (1) | 90,823 | (22,253 | ) | 174,506 | 73,659 | |||||||||||||
General and administrative | (9,679 | ) | (8,376 | ) | (18,352 | ) | (15,380 | ) | ||||||||||
Gain on disposition of assets | 3,483 | 651 | 3,399 | 1,239 | ||||||||||||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | 16,344 | 1,387 | 10,420 | (606 | ) | |||||||||||||
Interest expense, net | (4,591 | ) | (2,542 | ) | (8,152 | ) | (4,368 | ) | ||||||||||
Other | (91 | ) | 69 | (157 | ) | (64 | ) | |||||||||||
Income (loss) before income taxes | $ | 96,289 | $ | (31,064 | ) | $ | 161,664 | $ | 54,480 |
(1) | Total operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include non-operating revenues, general corporate expenses, gain on disposition of assets, interest expense, or income taxes. |
(2) | In June 2012, we had a non-cash ceiling test write-down of $115.9 million pre-tax ($72.1 million, net of tax). |
/s/ PricewaterhouseCoopers LLP |
Tulsa, Oklahoma |
August 6, 2013 |
• | General; |
• | Business Outlook; |
• | Executive Summary; |
• | Financial Condition and Liquidity; |
• | New Accounting Pronouncements; and |
• | Results of Operations. |
• | Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires, and produces oil and natural gas properties for our own account. |
• | Contract Drilling – carried out by our subsidiary Unit Drilling Company and its subsidiaries. This segment contracts to drill onshore oil and natural gas wells for others and for our own account. |
• | Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account. |
• | the quantity of natural gas, oil, and NGLs we produce; |
• | the prices we receive for our natural gas, oil, and NGLs production; |
• | the demand for and the dayrates we receive for our drilling rigs; and |
• | the margins we obtain from our natural gas gathering and processing contracts. |
June 30, | % Change | |||||||||
2013 | 2012 | |||||||||
(In thousands except percentages) | ||||||||||
Working capital | $ | 9,738 | $ | 41,538 | (77 | )% | ||||
Long-term debt | $ | 715,474 | $ | 332,900 | 115 | % | ||||
Shareholders’ equity | $ | 2,079,549 | $ | 2,000,378 | 4 | % | ||||
Ratio of long-term debt to total capitalization | 26 | % | 14 | % | 86 | % | ||||
Net income | $ | 99,213 | $ | 33,137 | 199 | % | ||||
Net cash provided by operating activities | $ | 317,888 | $ | 315,032 | 1 | % | ||||
Net cash used in investing activities | $ | (322,471 | ) | $ | (367,608 | ) | (12 | )% | ||
Net cash provided by financing activities | $ | 4,650 | $ | 52,826 | (91 | )% |
Six Months Ended June 30, | % Change | |||||||
2013 | 2012 | |||||||
Oil and Natural Gas: | ||||||||
Oil production (MBbls) | 1,656 | 1,506 | 10 | % | ||||
Natural gas liquids production (MBbls) | 1,739 | 1,330 | 31 | % | ||||
Natural gas production (MMcf) | 28,107 | 22,688 | 24 | % | ||||
Average oil price per barrel received | $95.05 | $94.04 | 1 | % | ||||
Average oil price per barrel received excluding hedges | $91.75 | $94.53 | (3 | )% | ||||
Average NGLs price per barrel received | $32.47 | $35.53 | (9 | )% | ||||
Average NGLs price per barrel received excluding hedges | $32.47 | $34.19 | (5 | )% | ||||
Average natural gas price per mcf received | $3.47 | $3.19 | 9 | % | ||||
Average natural gas price per mcf received excluding hedges | $3.53 | $2.18 | 62 | % | ||||
Contract Drilling: | ||||||||
Average number of our drilling rigs in use during the period | 65.8 | 79.1 | (17 | )% | ||||
Total number of drilling rigs owned at the end of the period | 126 | 128 | (2 | )% | ||||
Average dayrate | $19,590 | $19,979 | (2 | )% | ||||
Mid-Stream: | ||||||||
Gas gathered—Mcf/day | 299,582 | 239,837 | 25 | % | ||||
Gas processed—Mcf/day | 134,016 | 134,744 | (1 | )% | ||||
Gas liquids sold—gallons/day | 464,483 | 576,089 | (19 | )% | ||||
Number of natural gas gathering systems | 40 | 36 | 11 | % | ||||
Number of processing plants | 15 | 11 | 36 | % |
Lender | Participation Interest | |
BOK (BOKF, NA, dba Bank of Oklahoma) | 17 | % |
BBVA Compass Banks | 17 | % |
Bank of Montreal | 15 | % |
Bank of America, N.A. | 15 | % |
Comerica Bank | 8 | % |
Crédit Agricole Corporate and Investment Bank, London Branch | 8 | % |
Wells Fargo Bank, National Association | 8 | % |
Canadian Imperial Bank of Commerce | 8 | % |
The Bank of Nova Scotia | 4 | % |
100 | % |
• | the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% of our consolidated net income for the preceding fiscal year; |
• | the incurrence of additional debt with certain limited exceptions; and |
• | the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our properties, except in favor of our lenders. |
• | a current ratio (as defined in the credit agreement) of not less than 1 to 1; and |
• | a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1. |
Payments Due by Period | |||||||||||||||||||
Total | Less Than 1 Year | 2-3 Years | 4-5 Years | After 5 Years | |||||||||||||||
(In thousands) | |||||||||||||||||||
Long-term debt (1) | $ | 1,095,642 | $ | 44,423 | $ | 88,846 | $ | 156,404 | $ | 805,969 | |||||||||
Operating leases (2) | 12,339 | 8,411 | 3,676 | 252 | — | ||||||||||||||
Drill pipe, drilling components, and equipment purchases (3) | 5,583 | 5,583 | — | — | — | ||||||||||||||
Total contractual obligations | $ | 1,113,564 | $ | 58,417 | $ | 92,522 | $ | 156,656 | $ | 805,969 |
(1) | See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Notes and credit agreement and includes interest calculated using our June 30, 2013 interest rates of 6.625% for the Notes and 1.9% for the credit agreement. |
(2) | We lease office space or yards in Edmond, Oklahoma City, and Tulsa, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Pittsburgh, Pennsylvania under the terms of operating leases expiring through September, 2017. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. |
(3) | We have committed to pay $4.5 million for drilling equipment and $1.1 million for a processing plant over the next twelve months. |
Estimated Amount of Commitment Expiration Per Period | |||||||||||||||||||
Other Commitments | Total Accrued | Less Than 1 Year | 2-3 Years | 4-5 Years | After 5 Years | ||||||||||||||
(In thousands) | |||||||||||||||||||
Deferred compensation plan (1) | $ | 3,180 | Unknown | Unknown | Unknown | Unknown | |||||||||||||
Separation benefit plans (2) | $ | 8,562 | $ | 527 | Unknown | Unknown | Unknown | ||||||||||||
Derivative liabilities – commodity hedges | $ | 879 | $ | 879 | $ | — | $ | — | $ | — | |||||||||
Asset retirement liability (3) | $ | 137,039 | $ | 2,948 | $ | 43,362 | $ | 6,452 | $ | 84,277 | |||||||||
Gas balancing liability (4) | $ | 3,838 | Unknown | Unknown | Unknown | Unknown | |||||||||||||
Repurchase obligations (5) | $ | — | Unknown | Unknown | Unknown | Unknown | |||||||||||||
Workers’ compensation liability (6) | $ | 20,424 | $ | 8,661 | $ | 2,897 | $ | 1,254 | $ | 7,612 |
(1) | We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death, or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets, at the time of deferral. |
(2) | Effective January 1, 1997, we adopted a separation benefit plan (“Separation Plan”). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Currently there are no participants in the Senior Plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (“Special Plan”). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. On December 31, 2008, all these plans were amended to bring the plans into compliance with Section 409A of the Internal Revenue Code of 1986, as amended. |
(3) | When a well is drilled or acquired, under “Accounting for Asset Retirement Obligations,” we record the discounted fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells). |
(4) | We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners to recover their under-production from future production volumes. |
(5) | We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the “Partnerships”) with certain qualified employees, officers and directors from 1984 through 2011. One of our subsidiaries serves as the general partner of each of these programs. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. Repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $8,000 and $43,000 in 2013 and 2012, respectively through the first six months. |
(6) | We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment. |
Hedge Designation | |||||||||||
Cash Flow | Mark-to-Market | Total | Mark-to-Market | ||||||||
2013 | 2013 | 2013 | 2014 | ||||||||
Daily oil production | 58 | % | 30 | % | 88 | % | 53 | % | |||
Daily natural gas production | 52 | % | 13 | % | 65 | % | 33 | % |
June 30, 2013 | |||
(In millions) | |||
The Bank of Nova Scotia | $ | 5.8 | |
Bank of Montreal | 4.2 | ||
Comerica Bank | 3.2 | ||
Canadian Imperial Bank of Commerce | 1.1 | ||
BBVA Compass Bank | 0.5 | ||
Bank of America | (0.9 | ) | |
Total assets (liabilities) | $ | 13.9 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands) | |||||||||||||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net: | |||||||||||||||
Realized gains (losses) on derivatives not designated as hedges | $ | (181 | ) | $ | — | $ | 859 | $ | — | ||||||
Unrealized gains on derivatives not designated as hedges | 14,808 | — | 9,193 | — | |||||||||||
Unrealized gains (losses) on ineffectiveness of cash flow hedges | 1,717 | 1,387 | 368 | (606 | ) | ||||||||||
$ | 16,344 | $ | 1,387 | $ | 10,420 | $ | (606 | ) |
Quarter Ended June 30, | Percent Change | |||||||||
2013 | 2012 | |||||||||
Total revenue | $ | 340,421,000 | $ | 327,785,000 | 4 | % | ||||
Net income (loss) | $ | 59,007,000 | $ | (19,302,000 | ) | NM | ||||
Oil and Natural Gas: | ||||||||||
Revenue | $ | 164,799,000 | $ | 131,166,000 | 26 | % | ||||
Operating costs excluding depreciation, depletion, amortization, and impairment | $ | 44,994,000 | $ | 33,279,000 | 35 | % | ||||
Average oil price (Bbl) | $ | 94.89 | $ | 92.43 | 3 | % | ||||
Average NGLs price (Bbl) | $ | 30.32 | $ | 32.34 | (6 | )% | ||||
Average natural gas price (Mcf) | $ | 3.65 | $ | 3.03 | 20 | % | ||||
Oil production (Bbl) | 859,000 | 786,000 | 9 | % | ||||||
NGLs production (Bbl) | 935,000 | 674,000 | 39 | % | ||||||
Natural gas production (Mcf) | 13,887,000 | 11,287,000 | 23 | % | ||||||
Depreciation, depletion and amortization rate (Boe) | $ | 13.20 | $ | 16.92 | (22 | )% | ||||
Depreciation, depletion and amortization | $ | 55,335,000 | $ | 57,153,000 | (3 | )% | ||||
Impairment of oil and natural gas properties | — | 115,874,000 | (100 | )% | ||||||
Contract Drilling: | ||||||||||
Revenue | $ | 105,005,000 | $ | 146,872,000 | (29 | )% | ||||
Operating costs excluding depreciation | $ | 63,590,000 | $ | 74,819,000 | (15 | )% | ||||
Percentage of revenue from daywork contracts | 100 | % | 100 | % | ||||||
Average number of drilling rigs in use | 65.2 | 76.7 | (15 | )% | ||||||
Average dayrate on daywork contracts | $ | 19,601 | $ | 20,128 | (3 | )% | ||||
Depreciation | $ | 17,908,000 | $ | 21,238,000 | (16 | )% | ||||
Mid-Stream: | ||||||||||
Revenue | $ | 70,617,000 | $ | 49,747,000 | 42 | % | ||||
Operating costs excluding depreciation and amortization | $ | 59,557,000 | $ | 42,363,000 | 41 | % | ||||
Depreciation and amortization | $ | 8,214,000 | $ | 5,312,000 | 55 | % | ||||
Gas gathered—Mcf/day | 326,039 | 262,269 | 24 | % | ||||||
Gas processed—Mcf/day | 138,130 | 144,257 | (4 | )% | ||||||
Gas liquids sold—gallons/day | 508,189 | 629,350 | (19 | )% | ||||||
General and administrative expense | $ | 9,679,000 | $ | 8,376,000 | 16 | % | ||||
Gain on disposition of assets | $ | 3,483,000 | $ | 651,000 | NM | |||||
Other income (expense): (2) | ||||||||||
Interest expense, net | $ | (4,591,000 | ) | $ | (2,542,000 | ) | 81 | % | ||
Gain on derivatives not designated as hedges and hedge ineffectiveness | $ | 16,344,000 | $ | 1,387,000 | NM | |||||
Other | $ | (91,000 | ) | $ | 69,000 | NM | ||||
Income tax expense (benefit) | $ | 37,282,000 | $ | (11,762,000 | ) | NM | ||||
Average interest rate | 6.2 | % | 5.6 | % | 11 | % | ||||
Average long-term debt outstanding | $ | 719,710,000 | $ | 327,642,000 | 120 | % |
(1) | NM - A percentage calculation is not meaningful due to a percentage greater than 200. |
(2) | During the third quarter of 2012, we made the decision to prospectively use mark-to-market accounting for our economic hedges. Previously, we reported all realized and unrealized hedging gains (losses) in oil and natural gas revenues. We now reflect gains (losses) on non-designated hedges and the ineffectiveness from cash flow hedges along with other revenue items in other income (expense) below income from operations. Prior year amounts have been reclassified to conform to current year presentation. |
Six Months Ended June 30, | Percent Change | |||||||||
2013 | 2012 | |||||||||
Total revenue | $ | 658,953,000 | $ | 661,751,000 | — | % | ||||
Net income | $ | 99,213,000 | $ | 33,137,000 | 199 | % | ||||
Oil and Natural Gas: | ||||||||||
Revenue | $ | 318,408,000 | $ | 266,931,000 | 19 | % | ||||
Operating costs excluding depreciation, depletion, amortization and impairment | $ | 88,032,000 | $ | 68,888,000 | 28 | % | ||||
Average oil price (Bbl) | $ | 95.05 | $ | 94.04 | 1 | % | ||||
Average NGLs price (Bbl) | $ | 32.47 | $ | 35.53 | (9 | )% | ||||
Average natural gas price (Mcf) | $ | 3.47 | $ | 3.19 | 9 | % | ||||
Oil production (Bbl) | 1,656,000 | 1,506,000 | 10 | % | ||||||
NGLs production (Bbl) | 1,739,000 | 1,330,000 | 31 | % | ||||||
Natural gas production (Mcf) | 28,107,000 | 22,688,000 | 24 | % | ||||||
Depreciation, depletion and amortization rate (Boe) | $ | 13.08 | $ | 16.38 | (20 | )% | ||||
Depreciation, depletion and amortization | $ | 107,318,000 | $ | 109,350,000 | (2 | )% | ||||
Impairment of oil and natural gas properties | $ | — | $ | 115,874,000 | (100 | )% | ||||
Contract Drilling: | ||||||||||
Revenue | $ | 212,533,000 | $ | 287,778,000 | (26 | )% | ||||
Operating costs excluding depreciation | $ | 129,592,000 | $ | 150,992,000 | (14 | )% | ||||
Percentage of revenue from daywork contracts | 100 | % | 100 | % | ||||||
Average number of drilling rigs in use | 65.8 | 79.1 | (17 | )% | ||||||
Average dayrate on daywork contracts | $ | 19,590 | $ | 19,979 | (2 | )% | ||||
Depreciation | $ | 35,168,000 | $ | 42,566,000 | (17 | )% | ||||
Mid-Stream: | ||||||||||
Revenue | $ | 128,012,000 | $ | 107,042,000 | 20 | % | ||||
Operating costs excluding depreciation and amortization | $ | 108,967,000 | $ | 89,976,000 | 21 | % | ||||
Depreciation and amortization | $ | 15,370,000 | $ | 10,446,000 | 47 | % | ||||
Gas gathered—Mcf/day | 299,582 | 239,837 | 25 | % | ||||||
Gas processed—Mcf/day | 134,016 | 134,744 | (1 | )% | ||||||
Gas liquids sold—gallons/day | 464,483 | 576,089 | (19 | )% | ||||||
General and administrative expense | $ | 18,352,000 | $ | 15,380,000 | 19 | % | ||||
Gain on disposition of assets | $ | 3,399,000 | $ | 1,239,000 | 174 | % | ||||
Other income (expense): (2) | ||||||||||
Interest expense, net | $ | (8,152,000 | ) | $ | (4,368,000 | ) | (87 | )% | ||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness | $ | 10,420,000 | $ | (606,000 | ) | NM | ||||
Other | $ | (157,000 | ) | $ | (64,000 | ) | (145 | )% | ||
Income tax expense | $ | 62,451,000 | $ | 21,343,000 | 193 | % | ||||
Average interest rate | 6.3 | % | 5.7 | % | 11 | % | ||||
Average long-term debt outstanding | $ | 719,443,000 | $ | 315,864,000 | 128 | % |
(1) | NM - A percentage calculation is not meaningful due to a percentage greater than 200. |
(2) | During the third quarter of 2012, we made the decision to prospectively use mark-to-market accounting for our economic hedges. Previously, we reported all realized and unrealized hedging gains (losses) in oil and natural gas revenues. We now reflect gains (losses) on non-designated hedges and the ineffectiveness from cash flow hedges along with other revenue items in other income (expense) below income from operations. Prior year amounts have been reclassified to conform to current year presentation. |
• | the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures; |
• | the amount of wells we plan to drill or rework; |
• | prices for oil, NGLs, and natural gas; |
• | demand for oil NGLs, and natural gas; |
• | our exploration and drilling prospects; |
• | the estimates of our proved oil, NGLs, and natural gas reserves; |
• | oil, NGLs, and natural gas reserve potential; |
• | development and infill drilling potential; |
• | expansion and other development trends of the oil and natural gas industry; |
• | our business strategy; |
• | our plans to maintain or increase production of oil, NGLs, and natural gas; |
• | the number of gathering systems and processing plants we plan to construct or acquire; |
• | volumes and prices for natural gas gathered and processed; |
• | expansion and growth of our business and operations; |
• | demand for our drilling rigs and drilling rig rates; |
• | our belief that the final outcome of our legal proceedings will not materially affect our financial results; |
• | our ability to timely secure third-party services used in completing our wells; |
• | our ability to transport or convey our oil or natural gas production to established pipeline systems; |
• | impact of federal and state legislative and regulatory initiatives relating to hydrocarbon fracturing impacting our costs and increasing operating restrictions or delays as well as other adverse impacts on our business; |
• | our projected production guidelines for the year; |
• | our anticipated capital budgets; and |
• | the number of wells our oil and natural gas segment plans to drill during the year. |
• | the risk factors discussed in this report and in the documents we incorporate by reference; |
• | general economic, market, or business conditions; |
• | the availability of and nature or lack of business opportunities that we pursue; |
• | demand for our land drilling services; |
• | changes in laws or regulations; |
• | decreases or increases in commodity prices; and |
• | other factors, most of which are beyond our control. |
Term | Commodity | Hedged Volume | Weighted Average Fixed Price for Swaps | Hedged Market |
Jul’13 – Dec’13 | Crude oil – swap | 5,500 Bbl/day | $99.71 | WTI – NYMEX |
Jul’13 – Dec’13 | Natural gas – swap | 60,000 MMBtu/day | $3.56 | IF – NYMEX (HH) |
Jul’13 – Dec’13 | Natural gas – collar | 20,000 MMBtu/day | $3.25-3.72 | IF – NYMEX (HH) |
Term | Commodity | Hedged Volume | Weighted Average Fixed Price for Swaps | Hedged Market |
Jul’13 – Dec’13 | Crude oil – swap | 3,000 Bbl/day | $94.59 | WTI – NYMEX |
Jan’14 – Dec’14 | Crude oil – swap | 3,000 Bbl/day | $91.77 | WTI – NYMEX |
Jan’14 – Dec’14 | Crude oil – collar | 2,000 Bbl/day | $90.00-95.00 | WTI – NYMEX |
Jul’13 – Dec’13 | Natural gas – swap | 20,000 MMBtu/day | $3.94 | IF – NYMEX (HH) |
Jan’14 – Dec’14 | Natural gas – swap | 50,000 MMBtu/day | $4.24 | IF – NYMEX (HH) |
Term | Commodity | Hedged Volume | Weighted Average Fixed Price for Swaps | Hedged Market |
Jan’14 – Dec’14 | Crude oil – collar | 2,000 Bbl/day | $90.00-97.15 | WTI – NYMEX |
Period | (a) Total Number of Shares Purchased (1) | (b) Average Price Paid Per Share(2) | (c) Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (1) | (d) Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs | ||||||||
April 1, 2013 to April 30, 2013 | 8,237 | $ | 44.47 | 8,237 | — | |||||||
May 1, 2013 to May 31, 2013 | — | — | — | — | ||||||||
June 1, 2013 to June 30, 2013 | 88 | 44.47 | 88 | — | ||||||||
Total | 8,325 | $ | 44.47 | 8,325 | — |
(1) | The shares were repurchased to remit withholding of taxes on the value of stock distributed with the second quarter 2013 vesting for grants previously made from our “Unit Corporation Stock and Incentive Compensation Plan Amended and Restated May 2, 2012.” |
(2) | The price paid per common share represents the closing sales price of a share of our common stock as reported by the NYSE on the day that the stock was acquired by us. |
15 | Letter re: Unaudited Interim Financial Information. |
31.1 | Certification of Chief Executive Officer under Rule 13a – 14(a) of the Exchange Act. |
31.2 | Certification of Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act. |
32 | Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act and 18 U.S.C. Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002. |
101.INS | XBRL Instance Document. |
101.SCH | XBRL Taxonomy Extension Schema Document. |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document. |
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document. |
101.LAB | XBRL Taxonomy Extension Labels Linkbase Document. |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document. |
Unit Corporation | ||
Date: | August 6, 2013 | By: /s/ Larry D. Pinkston |
LARRY D. PINKSTON Chief Executive Officer and Director | ||
Date: | August 6, 2013 | By: /s/ David T. Merrill |
DAVID T. MERRILL | ||
Senior Vice President, Chief Financial Officer, and Treasurer |
By: | /s/ Larry D. Pinkston | |
Larry D. Pinkston | ||
Chief Executive Officer and | ||
Director |
By: | /s/ David T. Merrill | |
David T. Merrill | ||
Senior Vice President, Chief Financial Officer, and | ||
Treasurer |
Fair Value Measurements
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Jun. 30, 2013
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value. The highest priority is given to Level 1 and the lowest priority is given to Level 3. The levels are summarized as follows:
The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments. We corroborate these inputs based on recent transactions and broker quotes and compare the fair value with actual settlements. The following tables set forth our recurring fair value measurements:
All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of June 30, 2013. Certain natural gas fixed price swaps were transferred from Level 3 to Level 2 as of June 30, 2012 because of improvements in our ability to obtain and corroborate observable significant inputs to assess the fair value. Our policy is to recognize transfers either in or out of fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. Level 2 Fair Value Measurements Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index. Level 3 Fair Value Measurements Commodity Derivatives. The fair values of our natural gas and crude oil collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements. The following tables are reconciliations of our level 3 fair value measurements:
The following table provides quantitative information about our Level 3 unobservable inputs at June 30, 2013:
Based on our valuation at June 30, 2013, we determined that risk of non-performance by our counterparties was immaterial. Fair Value of Other Financial Instruments The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop these estimates. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. At June 30, 2013, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short term nature. Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreement at June 30, 2013 approximates its fair value. This debt would be classified as Level 2. The carrying amounts of long-term debt, net of unamortized discount, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012 were $645.5 million and $645.3 million, respectively. We estimated the fair value of these Notes using quoted marked prices at June 30, 2013 and December 31, 2012 which were $676.0 million and $687.7 million, respectively. These Notes would be classified as Level 2. |
Accumulated Other Comprehensive Income (Loss) (Schedule of accumulated other comprehensive income (loss)) (Details) (Commodity Derivatives [Member], USD $)
In Thousands, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||||||||||
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Jun. 30, 2013
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Jun. 30, 2012
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Jun. 30, 2013
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Jun. 30, 2012
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Amounts reclassified from accumulated other comprehensive income | $ (823) | $ 15,670 | $ 3,008 | $ 23,846 | ||||||||
Derivative Instruments, Gain Recognized in Income | 1,717 | 1,387 | 368 | (606) | ||||||||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax | 894 | 17,057 | 3,376 | 23,240 | ||||||||
Tax expense | (350) | (6,642) | (1,318) | (9,038) | ||||||||
Total reclassification for the period | 544 | 10,415 | 2,058 | 14,202 | ||||||||
Oil and natural gas revenue [Member]
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Amounts reclassified from accumulated other comprehensive income | (823) | [1] | 15,670 | [1] | 3,008 | [1] | 23,846 | [1] | ||||
Derivative Instruments, Gain Recognized in Income | 0 | 0 | 0 | 0 | ||||||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net [Member]
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Amounts reclassified from accumulated other comprehensive income | 0 | 0 | 0 | 0 | ||||||||
Derivative Instruments, Gain Recognized in Income | $ 1,717 | [2] | $ 1,387 | [2] | $ 368 | [2] | $ (606) | [2] | ||||
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Condensed Consolidated Statements Of Operations (USD $)
In Thousands, except Per Share data, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
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Jun. 30, 2013
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Jun. 30, 2012
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Jun. 30, 2013
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Jun. 30, 2012
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Revenues: | ||||
Oil and natural gas | $ 164,799 | $ 131,166 | $ 318,408 | $ 266,931 |
Contract drilling | 105,005 | 146,872 | 212,533 | 287,778 |
Gas gathering and processing | 70,617 | 49,747 | 128,012 | 107,042 |
Total revenues | 340,421 | 327,785 | 658,953 | 661,751 |
Oil and natural gas: | ||||
Operating costs | 44,994 | 33,279 | 88,032 | 68,888 |
Depreciation, depletion, and amortization | 55,335 | 57,153 | 107,318 | 109,350 |
Impairment of oil and natural gas properties (Note 2) | 0 | 115,874 | 0 | 115,874 |
Contract drilling: | ||||
Operating costs | 63,590 | 74,819 | 129,592 | 150,992 |
Depreciation | 17,908 | 21,238 | 35,168 | 42,566 |
Gas gathering and processing: | ||||
Operating costs | 59,557 | 42,363 | 108,967 | 89,976 |
Depreciation and amortization | 8,214 | 5,312 | 15,370 | 10,446 |
General and administrative | 9,679 | 8,376 | 18,352 | 15,380 |
Gain on dispostion of assets | (3,483) | (651) | (3,399) | (1,239) |
Total operating expenses | 255,794 | 357,763 | 499,400 | 602,233 |
Income (loss) from operations | 84,627 | (29,978) | 159,553 | 59,518 |
Other income (expense): | ||||
Interest, net | (4,591) | (2,542) | (8,152) | (4,368) |
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | 16,344 | 1,387 | 10,420 | (606) |
Other | (91) | 69 | (157) | (64) |
Total other income (expense) | 11,662 | (1,086) | 2,111 | (5,038) |
Income (loss) before income taxes | 96,289 | (31,064) | 161,664 | 54,480 |
Income tax expense (benefit): | ||||
Current | 2,117 | (2,066) | 4,634 | (2,066) |
Deferred | 35,165 | (9,696) | 57,817 | 23,409 |
Total income taxes | 37,282 | (11,762) | 62,451 | 21,343 |
Net income (loss) | $ 59,007 | $ (19,302) | $ 99,213 | $ 33,137 |
Net income (loss) per common share: | ||||
Basic | $ 1.22 | $ (0.40) | $ 2.06 | $ 0.69 |
Diluted | $ 1.22 | $ (0.40) | $ 2.05 | $ 0.69 |
Earnings Per Share
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share | EARNINGS (LOSS) PER SHARE Information related to the calculation of earnings per share follows:
Due to the net loss for the three months ended June 30, 2012, approximately 224,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and were excluded from the earnings per share calculation above. The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
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Stock-Based Compensation (Tables)
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule Of Fair Value Of The Restricted Stock Awards Granted During The Periods | The following table shows the fair value of any restricted stock awards granted to employees and non-employee directors during the periods indicated:
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Accumulated Other Comprehensive Income (Loss)
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Accumulated Other Comprehensive Income [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accumulated other comprehensive income | ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Changes in accumulated other comprehensive income (loss) by component, net of tax, for the three months ended June 30 are as follows:
Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Operations for the three months ended June 30 are as follows:
Changes in accumulated other comprehensive income (loss) by component, net of tax, for the six months ended June 30 are as follows:
Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Operations for the six months ended June 30 are as follows:
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Stock-Based Compensation (Schedule Of Fair Value Of The Restricted Stock Awards Granted During The Periods) (Details) (Restricted Stock [Member], USD $)
In Millions, except Share data, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
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Jun. 30, 2012
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Jun. 30, 2013
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Jun. 30, 2012
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Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares granted | 21,128 | 24,606 | 469,677 | 392,542 |
Estimated fair value (in millions) | $ 0.9 | $ 1.0 | $ 21.9 | $ 16.6 |
Employees [Member]
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||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares granted | 0 | 0 | 448,549 | 367,936 |
Estimated fair value (in millions) | 0 | 0 | 21.0 | 15.6 |
Percentage of shares granted expected to be distributed | 94.00% | 89.00% | ||
Non-employee Directors [Member]
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Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares granted | 21,128 | 24,606 | 21,128 | 24,606 |
Estimated fair value (in millions) | $ 0.9 | $ 1.0 | $ 0.9 | $ 1.0 |
Percentage of shares granted expected to be distributed | 100.00% | 100.00% | 100.00% | 100.00% |
Accumulated Other Comprehensive Income (Loss) (Tables)
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Statement of Other Comprehensive Income [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Changes in accumulated other comprehensive income (loss) | Changes in accumulated other comprehensive income (loss) by component, net of tax, for the three months ended June 30 are as follows:
Changes in accumulated other comprehensive income (loss) by component, net of tax, for the six months ended June 30 are as follows:
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Schedule of Accumulated Other Comprehensive Income (Loss) | Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Operations for the three months ended June 30 are as follows:
Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Operations for the six months ended June 30 are as follows:
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Fair Value Measurements (Tables)
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Recurring Fair Value Measurements | The following tables set forth our recurring fair value measurements:
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Reconciliations Of Level 3 Fair Value Measurements | The following tables are reconciliations of our level 3 fair value measurements:
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Schedule Of Quantitative Information About Unobservable Inputs | The following table provides quantitative information about our Level 3 unobservable inputs at June 30, 2013:
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Derivatives (Effect Of Derivative Instruments Recognized In Statement of Operations, Not Designated As Hedging Instruments) (Details) (USD $)
In Thousands, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
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Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | $ 14,627 | $ 0 | $ 10,052 | $ 0 |
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net [Member] | Commodity Derivatives [Member]
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||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | $ 14,627 | $ 0 | $ 10,052 | $ 0 |
Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) (USD $)
|
0 Months Ended | 6 Months Ended | |||
---|---|---|---|---|---|
Nov. 13, 2012
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Jul. 24, 2012
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May 18, 2011
|
Jun. 30, 2013
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Dec. 31, 2012
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Debt Instrument [Line Items] | |||||
Credit agreement with an average interest rate of 1.9% and 2.9% at June 30, 2013 and December 31, 2012, respectively | $ 70,000,000 | $ 71,100,000 | |||
6.625% senior subordinated notes due 2021, net of unamortized discount of $4.5 million at June 30, 2013 and $4.7 million at December 31, 2012 | 645,474,000 | 645,259,000 | |||
Total long-term debt | 715,474,000 | 716,359,000 | |||
Revolving credit facility interest rate | 1.90% | 2.90% | |||
Interest percentage of senior subordinated notes | 6.625% | 6.625% | 6.625% | 6.625% | |
Debt instrument maturity date | May 15, 2021 | May 15, 2021 | May 15, 2021 | May 15, 2021 | |
Debt instrument, unamortized discount | $ 4,500,000 | $ 4,700,000 |
Derivatives (Cash Flow Hedges Outstanding) (Details) (Designated as Hedging Instrument [Member], Jul'13 - Dec'13 [Member])
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6 Months Ended |
---|---|
Jun. 30, 2013
bbl
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Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | |
Weighted Average Fixed Price For Swaps | 99.71 |
Hedged Volume (in Bbl/day) | 5,500 |
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Start [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | |
Commodity Derivatives Term | Jul'13 |
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | End [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | |
Commodity Derivatives Term | Dec'13 |
Swap [Member] | If Nymex [Member] | Natural Gas [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | |
Weighted Average Fixed Price For Swaps | 3.56 |
Hedged Volume (MMBtu/day) | 60,000 |
Swap [Member] | If Nymex [Member] | Natural Gas [Member] | Start [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | |
Commodity Derivatives Term | Jul'13 |
Swap [Member] | If Nymex [Member] | Natural Gas [Member] | End [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | |
Commodity Derivatives Term | Dec'13 |
Collar [Member] | If Nymex [Member] | Natural Gas [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | |
Hedged Volume (MMBtu/day) | 20,000 |
Collar [Member] | If Nymex [Member] | Natural Gas [Member] | Start [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | |
Weighted Average Fixed Price For Swaps | 3.25 |
Commodity Derivatives Term | Jul'13 |
Collar [Member] | If Nymex [Member] | Natural Gas [Member] | End [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | |
Weighted Average Fixed Price For Swaps | 3.72 |
Commodity Derivatives Term | Dec'13 |
Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) (Collar [Member], USD $)
In Thousands, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2013
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Jun. 30, 2012
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Jun. 30, 2013
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Jun. 30, 2012
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Collar [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||||||
Beginning of period | $ (2,536) | $ 13,912 | $ (595) | $ 33,615 | ||||||
Included in earnings | 3,346 | [1] | 5,456 | [1] | 1,405 | [1] | 16,874 | [1] | ||
Included in other comprehensive income (loss) | 0 | (5,687) | 0 | (3,576) | ||||||
Settlements | 636 | (5,551) | 636 | (16,859) | ||||||
Transfers out of Level 3 into Level 2 | 0 | 0 | 0 | (21,924) | ||||||
End of period | 1,446 | 8,130 | 1,446 | 8,130 | ||||||
Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period | $ 3,982 | $ (95) | $ 2,041 | $ 15 | ||||||
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Earnings Per Share (Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share) (Details) (USD $)
|
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
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Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
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Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Stock options and SARs | 224,000 | |||
Stock options and SARs
|
||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Stock options and SARs | 250,901 | 292,901 | 149,665 | 250,901 |
Average exercise price | $ 52.72 | $ 50.99 | $ 58.41 | $ 52.72 |
Derivatives Derivatives (Schedule of Derivative Instruments, Gain (Loss) in Statement of Operations) (Details) (USD $)
In Thousands, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
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Jun. 30, 2012
|
Jun. 30, 2013
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Jun. 30, 2012
|
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Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | $ 16,344 | $ 1,387 | $ 10,420 | $ (606) |
Not Designated as Hedging Instrument [Member]
|
||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gains (losses) on derivatives not designated as hedges | (181) | 0 | 859 | 0 |
Unrealized gains on derivatives not designated as hedges | 14,808 | 0 | 9,193 | 0 |
Designated as Hedging Instrument [Member]
|
||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized gains (losses) on ineffectiveness of cash flow hedges | $ 1,717 | $ 1,387 | $ 368 | $ (606) |
Derivatives (Tables)
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash Flow Hedges Outstanding | At June 30, 2013, the following cash flow hedges were outstanding:
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Non-designated hedges outstanding | At June 30, 2013, the following non-designated hedges were outstanding:
After June 30, 2013, we entered into following non-designated hedges:
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Fair Value Of Derivative Instruments And Locations In Balance Sheets | The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
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Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance | These gains (losses) at June 30 are as follows:
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Amount Of Gain Or (Loss) Recognized In Accumulated OCI On Derivative | Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations (cash flow hedges) for the six months ended June 30:
(1) Net of taxes. |
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Gain Or Loss Of Reclassified Accumulated Other Comprehensive Income And Recognized In Income | Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations (cash flow hedges) for the six months ended June 30:
Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations (cash flow hedges) for the three months ended June 30:
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Effect Of Derivative Instruments Recognized In Statement Of Operations, Not Designated As Hedging Instruments | Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations (derivatives not designated as hedging instruments) for the three months ended June 30:
Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations (derivatives not designated as hedging instruments) for the six months ended June 30:
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Condensed Consolidated Statements Of Comprehensive Income (Loss) (Parenthetical) (USD $)
In Thousands, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
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Statement of Other Comprehensive Income [Abstract] | ||||
Change in value of derivative instruments used as cash flow hedges, tax | $ 3,874 | $ 17,256 | $ (2,504) | $ 16,214 |
Reclassification - derivative settlements, tax | 317 | (6,106) | (1,177) | (9,270) |
Ineffective portion of derivatives, tax | $ (667) | $ (537) | $ (141) | $ 232 |
Basis Of Preparation And Presentation
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6 Months Ended |
---|---|
Jun. 30, 2013
|
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Basis Of Preparation And Presentation [Abstract] | |
Basis Of Preparation And Presentation | BASIS OF PREPARATION AND PRESENTATION The accompanying unaudited condensed consolidated financial statements in this quarterly report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and, as appropriate, one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires. The accompanying condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This quarterly report should be read in conjunction with the audited consolidated financial statements and notes included in our Form 10-K, filed February 26, 2013, for the year ended December 31, 2012. In our management's opinion, the accompanying unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state the following: • Balance Sheets at June 30, 2013 and December 31, 2012; • Statements of Operations for the three and six months ended June 30, 2013 and 2012; • Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2013 and 2012; and • Statements of Cash Flows for the six months ended June 30, 2013 and 2012. Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and accompanying notes. Actual results may differ from those estimates. Results for the six months ended June 30, 2013 and 2012 are not necessarily indicative of the results to be realized for the full year in the case of 2013, or that we realized for the full year of 2012. Certain amounts in the accompanying unaudited condensed consolidated financial statements for prior periods have been reclassified to conform to current year presentation. Certain financial statement captions were expanded or combined with no impact to consolidated net income or shareholders' equity. With respect to the unaudited financial information for the three and six month periods ended June 30, 2013 and 2012, our auditors, PricewaterhouseCoopers LLP, reported that it applied limited procedures in accordance with professional standards in reviewing that information. Its separate report, dated August 6, 2013, which is included in this quarterly report, states that it did not audit and it does not express an opinion on that unaudited financial information. Accordingly, the degree of reliance placed on its report should be restricted in light of the limited review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 (Act) for its report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act. |
Accrued Liabilities
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Accounts Payable and Accrued Liabilities, Current [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accrued Liabilities | ACCRUED LIABILITIES Accrued liabilities consisted of the following:
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Oil And Natural Gas Properties
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6 Months Ended |
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Jun. 30, 2013
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Extractive Industries [Abstract] | |
Oil And Natural Gas Properties | OIL AND NATURAL GAS PROPERTIES Full cost accounting rules require us to review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is referred to as the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the unescalated 12-month average price of our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. In the event the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short period of time. Once incurred, a write-down of oil and natural gas properties is not reversible. For the quarter ended June 30, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased significantly, resulting in a non-cash ceiling test write down of $115.9 million pre-tax ($72.1 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination as of June 30, 2012, consisted of swaps covering 2.9 MMBoe in 2012 and 4.5 MMBoe in 2013. The effect of those hedges on the June 30, 2012 ceiling test was a $32.5 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. At June 30, 2013, the 12-month average commodity prices, including the discounted value of our cash flow hedges, were at levels that did not require us to take a write-down of our oil and natural gas properties. If there are declines in the 12-month average prices, including the discounted value of our cash flow hedges, we may be required to record a write-down in future periods. Our qualifying cash flow hedges used in the ceiling test determination as of June 30, 2013, consisted of swaps and collars covering 3.5 MMBoe in 2013. The effect of those hedges on the June 30, 2013 ceiling test was a $9.4 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Even without the impact of those hedges, we would not have been required to take a write-down for the quarter. Our oil, NGLs, and natural gas hedging is discussed in Note 9 of the Notes to our Unaudited Condensed Consolidated Financial Statements. |
Derivatives Derivatives (Schedule of Non-designated Hedges Outstanding) (Details) (Not Designated as Hedging Instrument [Member])
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6 Months Ended |
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Jun. 30, 2013
bbl
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Swap [Member] | Jul'13 - Dec'13 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
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Derivative [Line Items] | |
Weighted Average Fixed Price For Swaps | 94.59 |
Hedged Volume (in Bbl/day) | 3,000 |
Swap [Member] | Jul'13 - Dec'13 [Member] | Crude Oil [Member] | WTI - NYMEX [Member] | Start [Member]
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Derivative [Line Items] | |
Commodity Derivatives Term | Jul'13 |
Swap [Member] | Jul'13 - Dec'13 [Member] | Crude Oil [Member] | WTI - NYMEX [Member] | End [Member]
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Derivative [Line Items] | |
Commodity Derivatives Term | Dec'13 |
Swap [Member] | Jul'13 - Dec'13 [Member] | Natural Gas [Member] | If Nymex [Member]
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Derivative [Line Items] | |
Weighted Average Fixed Price For Swaps | 3.94 |
Hedged Volume (in MMBtu/day) | 20,000 |
Swap [Member] | Jul'13 - Dec'13 [Member] | Natural Gas [Member] | If Nymex [Member] | Start [Member]
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Derivative [Line Items] | |
Commodity Derivatives Term | Jul'13 |
Swap [Member] | Jul'13 - Dec'13 [Member] | Natural Gas [Member] | If Nymex [Member] | End [Member]
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Derivative [Line Items] | |
Commodity Derivatives Term | Dec'13 |
Swap [Member] | Jan'14 - Dec'14 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
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Derivative [Line Items] | |
Weighted Average Fixed Price For Swaps | 91.77 |
Hedged Volume (in Bbl/day) | 3,000 |
Swap [Member] | Jan'14 - Dec'14 [Member] | Crude Oil [Member] | WTI - NYMEX [Member] | Start [Member]
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Derivative [Line Items] | |
Commodity Derivatives Term | Jan'14 |
Swap [Member] | Jan'14 - Dec'14 [Member] | Crude Oil [Member] | WTI - NYMEX [Member] | End [Member]
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Derivative [Line Items] | |
Commodity Derivatives Term | Dec'14 |
Swap [Member] | Jan'14 - Dec'14 [Member] | Natural Gas [Member] | If Nymex [Member]
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Derivative [Line Items] | |
Weighted Average Fixed Price For Swaps | 4.24 |
Hedged Volume (in MMBtu/day) | 50,000 |
Swap [Member] | Jan'14 - Dec'14 [Member] | Natural Gas [Member] | If Nymex [Member] | Start [Member]
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Derivative [Line Items] | |
Commodity Derivatives Term | Jan'14 |
Swap [Member] | Jan'14 - Dec'14 [Member] | Natural Gas [Member] | If Nymex [Member] | End [Member]
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Derivative [Line Items] | |
Commodity Derivatives Term | Dec'14 |
Collar [Member] | Jan'14 - Dec'14 [Member] | Crude Oil [Member] | WTI - NYMEX [Member]
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Derivative [Line Items] | |
Hedged Volume (in Bbl/day) | 2,000 |
Collar [Member] | Jan'14 - Dec'14 [Member] | Crude Oil [Member] | WTI - NYMEX [Member] | Start [Member]
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Derivative [Line Items] | |
Weighted Average Fixed Price For Swaps | 90.00 |
Commodity Derivatives Term | Jan'14 |
Collar [Member] | Jan'14 - Dec'14 [Member] | Crude Oil [Member] | WTI - NYMEX [Member] | End [Member]
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Derivative [Line Items] | |
Weighted Average Fixed Price For Swaps | 95.00 |
Commodity Derivatives Term | Dec'14 |
Collar [Member] | Jan'14 - Dec'14 [Member] | Crude Oil [Member] | WTI - NYMEX [Member] | Subsequent Event [Member]
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Derivative [Line Items] | |
Hedged Volume (in Bbl/day) | 2,000 |
Collar [Member] | Jan'14 - Dec'14 [Member] | Crude Oil [Member] | WTI - NYMEX [Member] | Subsequent Event [Member] | Start [Member]
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Derivative [Line Items] | |
Weighted Average Fixed Price For Swaps | 90.00 |
Commodity Derivatives Term | Jan'14 |
Collar [Member] | Jan'14 - Dec'14 [Member] | Crude Oil [Member] | WTI - NYMEX [Member] | Subsequent Event [Member] | End [Member]
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Derivative [Line Items] | |
Weighted Average Fixed Price For Swaps | 97.15 |
Commodity Derivatives Term | Dec'14 |
Industry Segment Information (Tables)
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Jun. 30, 2013
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Industry segment information | The following table provides certain information about the operations of each of our segments:
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Earnings Per Share Earnings per Share (Narrative) (Details)
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3 Months Ended |
---|---|
Jun. 30, 2012
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Earnings Per Share [Abstract] | |
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 224,000 |
Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) (USD $)
In Thousands, unless otherwise specified |
6 Months Ended | |||||
---|---|---|---|---|---|---|
Jun. 30, 2013
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Jun. 30, 2012
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Asset Retirement Obligation Disclosure [Abstract] | ||||||
ARO liability, January 1: | $ 146,159 | $ 96,446 | ||||
Accretion of discount | 2,825 | 2,126 | ||||
Liability incurred | 2,869 | 4,420 | ||||
Liability settled | (3,516) | (1,447) | ||||
Revision of estimates | (11,298) | [1] | (5,022) | [1] | ||
ARO liability, June 30: | 137,039 | 96,523 | ||||
Less current portion | 2,948 | 2,909 | ||||
Total long-term ARO | $ 134,091 | $ 93,614 | ||||
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