Nevada | 95-2636730 |
(State of Incorporation) | (I.R.S. Employer Identification No.) |
Large accelerated filer £ | Accelerated filer x |
Non-accelerated filer £ (Do not check if a smaller reporting company) | Smaller reporting company o |
PART I - FINANCIAL INFORMATION | Page | ||
Item 1. | |||
Item 2. | |||
Item 3. | |||
Item 4. | |||
PART II – OTHER INFORMATION | |||
Item 1. | |||
Item 1A. | |||
Item 2. | |||
Item 3. | |||
Item 4. | |||
Item 5. | |||
Item 6. | |||
• | changes in production volumes and worldwide demand; |
• | volatility of commodity prices for natural gas and crude oil; |
• | changes in estimates of proved reserves; |
• | inaccuracy of reserve estimates and expected production rates; |
• | declines in the values of our natural gas and crude oil properties resulting in impairments; |
• | the future cash flow, liquidity and financial position of the Company; |
• | the timing and extent of our success in discovering, acquiring, developing and producing reserves; |
• | our ability to acquire leases, drilling rigs, supplies and services at reasonable prices; |
• | reductions in the borrowing base under our credit facility; |
• | risks incidental to the drilling and operation of natural gas and crude oil wells; |
• | the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price; |
• | changes in environmental laws, the regulation and enforcement of those laws and the costs to comply with those laws; |
• | the impact of environmental events, governmental responses to the events and our ability to insure adequately against such events; |
• | the timing and receipt of necessary regulatory permits; |
• | competition in the oil and gas industry; |
• | the success of the Company in marketing oil and gas; |
• | the effect of natural gas and crude oil derivatives activities; |
• | the availability and cost of capital to us; |
• | the cost of pending or future litigation; |
• | our ability to retain or attract senior management and key technical employees; and |
• | the success of strategic plans, expectations and objectives for future operations of the Company. |
June 30, 2011 | December 31, 2010 (1) | ||||||
Assets | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 6,771 | $ | 54,372 | |||
Accounts receivable, net | 57,221 | 53,978 | |||||
Accounts receivable affiliates | 9,257 | 11,448 | |||||
Fair value of derivatives | 38,797 | 42,953 | |||||
Prepaid expenses and other current assets | 15,855 | 14,072 | |||||
Total current assets | 127,901 | 176,823 | |||||
Properties and equipment, net | 1,244,413 | 1,120,038 | |||||
Assets held for sale | — | 5,191 | |||||
Fair value of derivatives | 34,546 | 44,464 | |||||
Accounts receivable affiliates | 4,819 | 8,478 | |||||
Other assets | 32,006 | 34,041 | |||||
Total Assets | $ | 1,443,685 | $ | 1,389,035 | |||
Liabilities and Equity | |||||||
Liabilities | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 103,620 | $ | 47,271 | |||
Accounts payable affiliates | 8,084 | 9,605 | |||||
Production tax liability | 18,490 | 16,226 | |||||
Fair value of derivatives | 30,349 | 29,998 | |||||
Funds held for distribution | 30,755 | 29,755 | |||||
Accrued interest payable | 10,396 | 10,051 | |||||
Other accrued expenses | 21,408 | 17,723 | |||||
Total current liabilities | 223,102 | 160,629 | |||||
Long-term debt | 314,124 | 295,695 | |||||
Deferred income taxes | 179,711 | 187,999 | |||||
Asset retirement obligations | 28,414 | 27,797 | |||||
Fair value of derivatives | 32,230 | 36,644 | |||||
Accounts payable affiliates | 7,353 | 12,111 | |||||
Other liabilities | 21,360 | 25,919 | |||||
Total liabilities | 806,294 | 746,794 | |||||
Commitments and contingent liabilities | |||||||
Equity | |||||||
Shareholders' equity: | |||||||
Preferred shares, par value $0.01 per share; authorized 50,000,000 shares; issued: none | — | — | |||||
Common shares, par value $0.01 per share; authorized 100,000,000 shares; issued: 23,565,040 in 2011 and 23,462,326 in 2010 | 236 | 235 | |||||
Additional paid-in capital | 215,237 | 209,198 | |||||
Retained earnings | 422,084 | 432,843 | |||||
Treasury shares, at cost: 6,238 in 2011 and 2,938 in 2010 | (242 | ) | (111 | ) | |||
Total shareholders' equity | 637,315 | 642,165 | |||||
Noncontrolling interest in subsidiary | 76 | 76 | |||||
Total equity | 637,391 | 642,241 | |||||
Total Liabilities and Equity | $ | 1,443,685 | $ | 1,389,035 | |||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
Revenues: | |||||||||||||||
Natural gas, NGL and crude oil sales | $ | 72,215 | $ | 48,729 | $ | 136,094 | $ | 106,556 | |||||||
Sales from natural gas marketing | 18,897 | 12,589 | 34,099 | 35,276 | |||||||||||
Commodity price risk management gain (loss), net | 20,537 | 12,257 | (3,345 | ) | 55,479 | ||||||||||
Well operations, pipeline income and other | 1,781 | 2,148 | 3,657 | 4,737 | |||||||||||
Total revenues | 113,430 | 75,723 | 170,505 | 202,048 | |||||||||||
Costs, expenses and other: | |||||||||||||||
Production costs | 19,674 | 16,004 | 40,713 | 30,965 | |||||||||||
Cost of natural gas marketing | 18,207 | 12,207 | 33,200 | 34,530 | |||||||||||
Exploration expense | 1,720 | 3,830 | 3,871 | 10,248 | |||||||||||
General and administrative expense | 19,509 | 9,855 | 33,382 | 20,549 | |||||||||||
Depreciation, depletion and amortization | 32,674 | 26,945 | 65,031 | 54,403 | |||||||||||
Gain on sale of properties and equipment | — | (96 | ) | — | (96 | ) | |||||||||
Total costs, expenses and other | 91,784 | 68,745 | 176,197 | 150,599 | |||||||||||
Income (loss) from operations | 21,646 | 6,978 | (5,692 | ) | 51,449 | ||||||||||
Interest income | 2 | 34 | 11 | 39 | |||||||||||
Interest expense | (9,067 | ) | (7,672 | ) | (18,129 | ) | (15,472 | ) | |||||||
Income (loss) from continuing operations before income taxes | 12,581 | (660 | ) | (23,810 | ) | 36,016 | |||||||||
Provision (benefit) for income taxes | 3,416 | (238 | ) | (10,431 | ) | 13,566 | |||||||||
Income (loss) from continuing operations | 9,165 | (422 | ) | (13,379 | ) | 22,450 | |||||||||
Income (loss) from discontinued operations, net of tax | — | (2,313 | ) | 2,620 | (1,516 | ) | |||||||||
Net income (loss) | 9,165 | (2,735 | ) | (10,759 | ) | 20,934 | |||||||||
Less: net loss attributable to noncontrolling interests | — | (6 | ) | — | (61 | ) | |||||||||
Net income (loss) attributable to shareholders | $ | 9,165 | $ | (2,729 | ) | $ | (10,759 | ) | $ | 20,995 | |||||
Amounts attributable to Petroleum Development Corporation shareholders: | |||||||||||||||
Income (loss) from continuing operations | $ | 9,165 | $ | (416 | ) | $ | (13,379 | ) | $ | 22,511 | |||||
Income (loss) from discontinued operations, net of tax | — | (2,313 | ) | 2,620 | (1,516 | ) | |||||||||
Net income (loss) attributable to shareholders | $ | 9,165 | $ | (2,729 | ) | $ | (10,759 | ) | $ | 20,995 | |||||
Earnings (loss) per share attributable to shareholders: | |||||||||||||||
Basic | |||||||||||||||
Income (loss) from continuing operations | $ | 0.39 | $ | (0.03 | ) | $ | (0.57 | ) | $ | 1.17 | |||||
Income (loss) from discontinued operations | — | (0.12 | ) | 0.11 | (0.08 | ) | |||||||||
Net income (loss) attributable to shareholders | $ | 0.39 | $ | (0.15 | ) | $ | (0.46 | ) | $ | 1.09 | |||||
Diluted | |||||||||||||||
Income (loss) from continuing operations | $ | 0.39 | $ | (0.03 | ) | $ | (0.57 | ) | $ | 1.17 | |||||
Income (loss) from discontinued operations | — | (0.12 | ) | 0.11 | (0.08 | ) | |||||||||
Net income (loss) attributable to shareholders | $ | 0.39 | $ | (0.15 | ) | $ | (0.46 | ) | $ | 1.09 | |||||
Weighted average common shares outstanding: | |||||||||||||||
Basic | 23,491 | 19,213 | 23,460 | 19,202 | |||||||||||
Diluted | 23,723 | 19,213 | 23,460 | 19,296 | |||||||||||
Six Months Ended June 30, | |||||||
2011 | 2010 | ||||||
Cash flows from operating activities: | |||||||
Net income (loss) | $ | (10,759 | ) | $ | 20,934 | ||
Adjustments to net income (loss) to reconcile to net cash provided by operating activities: | |||||||
Unrealized (gain) loss on derivatives, net | 9,094 | (24,701 | ) | ||||
Depreciation, depletion and amortization | 65,031 | 55,867 | |||||
Amortization and impairment of natural gas and crude oil properties | 952 | 5,662 | |||||
Exploratory dry hole costs | 171 | 3,552 | |||||
Loss (gain) from sale of properties and equipment | (3,928 | ) | 169 | ||||
Deferred income taxes | (10,543 | ) | 11,885 | ||||
Other | 10,175 | 4,811 | |||||
Changes in assets and liabilities | 11,401 | 17,192 | |||||
Net cash provided by operating activities | 71,594 | 95,371 | |||||
Cash flows from investing activities: | |||||||
Capital expenditures | (151,355 | ) | (77,861 | ) | |||
Deconsolidation/change in ownership effect on cash and cash equivalents | (101 | ) | (3,472 | ) | |||
Proceeds from sale of properties and equipment | 10,062 | 746 | |||||
Other | 1,643 | — | |||||
Net cash used in investing activities | (139,751 | ) | (80,587 | ) | |||
Cash flows from financing activities: | |||||||
Proceeds from credit facility | 65,927 | 130,000 | |||||
Payment of credit facility | (49,526 | ) | (173,000 | ) | |||
Contribution by investing partner in PDCM | 6,407 | 16,173 | |||||
Other | (2,252 | ) | (454 | ) | |||
Net cash provided by (used in) financing activities | 20,556 | (27,281 | ) | ||||
Net decrease in cash and cash equivalents | (47,601 | ) | (12,497 | ) | |||
Cash and cash equivalents, beginning of period | 54,372 | 31,944 | |||||
Cash and cash equivalents, end of period | $ | 6,771 | $ | 19,447 | |||
Supplemental cash flow information: | |||||||
Cash payments (receipts) for: | |||||||
Interest, net of capitalized interest | $ | 14,328 | $ | 15,607 | |||
Income taxes, net of refunds | 148 | (27,042 | ) | ||||
Non-cash investing activities: | |||||||
Change in accounts payable related to purchases of properties and equipment, including 2005 Partnership acquisition | 48,572 | 10,944 | |||||
Change in asset retirement obligation, with a corresponding increase to properties and equipment, net of disposals | 304 | 723 | |||||
June 30, 2011 | December 31, 2010 | ||||||
(in thousands) | |||||||
Cash and cash equivalents | $ | 578 | $ | 1,560 | |||
Other current assets | 4,230 | 3,206 | |||||
Total current assets | 4,808 | 4,766 | |||||
Properties and equipment, net | 109,324 | 101,679 | |||||
Other assets | 2,104 | 1,986 | |||||
Total assets | 116,236 | 108,431 | |||||
Total current liabilities | 4,659 | 4,641 | |||||
Long-term debt | 7,900 | — | |||||
Asset retirement obligations | 8,408 | 8,681 | |||||
Other liabilities | 1,651 | 1,370 | |||||
Total liabilities | 22,618 | 14,692 | |||||
June 30, 2011 | December 31, 2010 (a) | ||||||||||||||||||||||
Level 2 (b) | Level 3 (c) | Total | Level 2 (b) | Level 3 (c) | Total | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
Assets: | |||||||||||||||||||||||
Commodity based derivatives contracts | $ | 61,089 | $ | 12,198 | $ | 73,287 | $ | 72,880 | $ | 14,426 | $ | 87,306 | |||||||||||
Basis protection derivative contracts | — | 56 | 56 | 10 | 101 | 111 | |||||||||||||||||
Total assets | 61,089 | 12,254 | 73,343 | 72,890 | 14,527 | 87,417 | |||||||||||||||||
Liabilities: | |||||||||||||||||||||||
Commodity based derivatives contracts | 14,076 | 6,464 | 20,540 | 16,304 | 3,758 | 20,062 | |||||||||||||||||
Basis protection derivative contracts | 42,039 | — | 42,039 | 46,573 | 7 | 46,580 | |||||||||||||||||
Total liabilities | 56,115 | 6,464 | 62,579 | 62,877 | 3,765 | 66,642 | |||||||||||||||||
Net asset | $ | 4,974 | $ | 5,790 | $ | 10,764 | $ | 10,013 | $ | 10,762 | $ | 20,775 | |||||||||||
(a) | We reclassified our NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by $64.1 million, with a corresponding increase in Level 2), PEPL and CIG-based natural gas fixed-price swaps, crude oil fixed-price swaps, basis swaps and natural gas physical purchases from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by $54.1 million, with a corresponding increase in Level 2). The amounts presented reflect these reclassifications and conform to current period presentation. |
(b) | Includes our fixed-price swaps, basis swaps and physical purchases. |
(c) | Includes our natural gas and crude oil collars, crude oil puts and physical sales. |
Six Months Ended June 30, | ||||||||
2011 | 2010 (1) | |||||||
(in thousands) | ||||||||
Fair value, net asset, beginning of period | $ | 10,762 | $ | 15,048 | ||||
Changes in fair value included in statement of operations line item: | ||||||||
Commodity price risk management gain (loss), net | (2,108 | ) | 12,912 | |||||
Sales from natural gas marketing | 20 | 352 | ||||||
Cost of natural gas marketing | — | 23 | ||||||
Changes in fair value included in balance sheet line item (2): | ||||||||
Accounts receivable affiliates | 49 | 10 | ||||||
Accounts payable affiliates | (637 | ) | (1,468 | ) | ||||
Settlements included in statement of operations line items: | ||||||||
Commodity price risk management gain (loss), net | (2,210 | ) | (11,144 | ) | ||||
Sales from natural gas marketing | (86 | ) | (183 | ) | ||||
Cost of natural gas marketing | — | (23 | ) | |||||
Fair value, net asset, end of period | $ | 5,790 | $ | 15,527 | ||||
Changes in unrealized gains (losses) relating to assets (liabilities) still held | ||||||||
as of period end, included in statement of operations line item: | ||||||||
Commodity price risk management gain (loss), net | $ | (1,809 | ) | 12,560 | ||||
Sales from natural gas marketing | (5 | ) | 176 | |||||
$ | (1,814 | ) | $ | 12,736 | ||||
(1) | We reclassified our PEPL and CIG-based natural gas fixed-price swaps, crude oil fixed-price swaps, basis swaps and natural gas physical purchases from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of the period by $44.0 million). The amounts presented reflect these reclassifications and conform to current period presentation. |
(2) | Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships. |
Fair Value | |||||||||||
Derivatives instruments not designated as hedges (1): | Balance sheet line item | June 30, 2011 | December 31, 2010 | ||||||||
(in thousands) | |||||||||||
Derivative assets: | Current | ||||||||||
Commodity contracts | |||||||||||
Related to natural gas and crude oil sales | Fair value of derivatives | $ | 31,102 | $ | 32,837 | ||||||
Related to affiliated partnerships (2) | Fair value of derivatives | 6,665 | 8,231 | ||||||||
Related to natural gas marketing | Fair value of derivatives | 980 | 1,811 | ||||||||
Basis protection contracts | |||||||||||
Related to natural gas marketing | Fair value of derivatives | 50 | 74 | ||||||||
38,797 | 42,953 | ||||||||||
Non Current | |||||||||||
Commodity contracts | |||||||||||
Related to natural gas and crude oil sales | Fair value of derivatives | 27,180 | 32,270 | ||||||||
Related to affiliated partnerships (2) | Fair value of derivatives | 7,353 | 12,111 | ||||||||
Related to natural gas marketing | Fair value of derivatives | 7 | 46 | ||||||||
Basis protection contracts | |||||||||||
Related to natural gas marketing | Fair value of derivatives | 6 | 37 | ||||||||
34,546 | 44,464 | ||||||||||
Total derivative assets | $ | 73,343 | $ | 87,417 | |||||||
Derivative liabilities: | Current | ||||||||||
Commodity contracts | |||||||||||
Related to natural gas and crude oil sales | Fair value of derivatives | $ | 9,881 | $ | 10,636 | ||||||
Related to affiliated partnerships (3) | Fair value of derivatives | 760 | 1,676 | ||||||||
Related to natural gas marketing | Fair value of derivatives | 767 | 1,492 | ||||||||
Basis protection contracts | |||||||||||
Related to natural gas and crude oil sales | Fair value of derivatives | 14,983 | 11,725 | ||||||||
Related to affiliated partnerships (3) | Fair value of derivatives | 3,947 | 4,462 | ||||||||
Related to natural gas marketing | Fair value of derivatives | 11 | 7 | ||||||||
30,349 | 29,998 | ||||||||||
Non Current | |||||||||||
Commodity contracts | |||||||||||
Related to natural gas and crude oil sales | Fair value of derivatives | 9,171 | 6,231 | ||||||||
Related to affiliated partnerships (3) | Fair value of derivatives | (25 | ) | (3 | ) | ||||||
Related to natural gas marketing | Fair value of derivatives | (14 | ) | 30 | |||||||
Basis protection contracts | |||||||||||
Related to natural gas and crude oil sales | Fair value of derivatives | 18,255 | 21,905 | ||||||||
Related to affiliated partnerships (3) | Fair value of derivatives | 4,844 | 8,481 | ||||||||
Related to natural gas marketing | Fair value of derivatives | (1 | ) | — | |||||||
32,230 | 36,644 | ||||||||||
Total derivative liabilities | $ | 62,579 | $ | 66,642 | |||||||
2011 | 2010 | |||||||||||||||||||||||
Statement of operations line item | Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized | Realized and Unrealized Gains (Losses) For the Current Period | Total | Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized | Realized and Unrealized Gains (Losses) For the Current Period | Total | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Three Months Ended June 30, | ||||||||||||||||||||||||
Commodity price risk management gain, net | ||||||||||||||||||||||||
Realized gains | $ | 763 | $ | 1,040 | $ | 1,803 | $ | 7,503 | $ | 390 | $ | 7,893 | ||||||||||||
Unrealized gains (losses) | (763 | ) | 19,497 | 18,734 | (7,503 | ) | 11,867 | 4,364 | ||||||||||||||||
Total commodity price risk management gain, net (1) | $ | — | $ | 20,537 | $ | 20,537 | $ | — | $ | 12,257 | $ | 12,257 | ||||||||||||
Sales from natural gas marketing | ||||||||||||||||||||||||
Realized gains (losses) | $ | 473 | $ | 19 | $ | 492 | $ | 1,984 | $ | (179 | ) | $ | 1,805 | |||||||||||
Unrealized gains (losses) | (473 | ) | 456 | (17 | ) | (1,984 | ) | (580 | ) | (2,564 | ) | |||||||||||||
Total sales from natural gas marketing (2) | $ | — | $ | 475 | $ | 475 | $ | — | $ | (759 | ) | $ | (759 | ) | ||||||||||
Cost of natural gas marketing | ||||||||||||||||||||||||
Realized gains (losses) | $ | (370 | ) | $ | (31 | ) | $ | (401 | ) | $ | (1,747 | ) | $ | 138 | $ | (1,609 | ) | |||||||
Unrealized gains (losses) | 370 | (436 | ) | (66 | ) | 1,747 | 664 | 2,411 | ||||||||||||||||
Total cost of natural gas marketing (2) | $ | — | $ | (467 | ) | $ | (467 | ) | $ | — | $ | 802 | $ | 802 | ||||||||||
Six Months Ended June 30, | ||||||||||||||||||||||||
Commodity price risk management gain (loss), net | ||||||||||||||||||||||||
Realized gains (losses) | $ | 6,612 | $ | (1,021 | ) | $ | 5,591 | $ | 21,604 | $ | 9,213 | $ | 30,817 | |||||||||||
Unrealized gains (losses) | (6,612 | ) | (2,324 | ) | (8,936 | ) | (21,604 | ) | 46,266 | 24,662 | ||||||||||||||
Total commodity price risk management gain (loss), net (1) | $ | — | $ | (3,345 | ) | $ | (3,345 | ) | $ | — | $ | 55,479 | $ | 55,479 | ||||||||||
Sales from natural gas marketing | ||||||||||||||||||||||||
Realized gains | $ | 1,373 | $ | 261 | $ | 1,634 | $ | 1,481 | $ | 1,383 | $ | 2,864 | ||||||||||||
Unrealized gains (losses) | (1,373 | ) | 339 | (1,034 | ) | (1,481 | ) | 2,429 | 948 | |||||||||||||||
Total sales from natural gas marketing (2) | $ | — | $ | 600 | $ | 600 | $ | — | $ | 3,812 | $ | 3,812 | ||||||||||||
Cost of natural gas marketing | ||||||||||||||||||||||||
Realized losses | $ | (1,076 | ) | $ | (285 | ) | $ | (1,361 | ) | $ | (1,329 | ) | $ | (1,376 | ) | $ | (2,705 | ) | ||||||
Unrealized gains (losses) | 1,076 | (200 | ) | 876 | 1,329 | (2,238 | ) | (909 | ) | |||||||||||||||
Total cost of natural gas marketing (2) | $ | — | $ | (485 | ) | $ | (485 | ) | $ | — | $ | (3,614 | ) | $ | (3,614 | ) | ||||||||
Counterparty Name | Fair Value of Derivative Assets As of June 30, 2011 | |||
(in thousands) | ||||
JPMorgan Chase Bank, N.A. (1) | $ | 35,423 | ||
Crèdit Agricole CIB (1) | 21,978 | |||
Wells Fargo Bank, N.A. (1) | 12,998 | |||
Various (2) | 2,944 | |||
Total | $ | 73,343 | ||
June 30, 2011 | December 31, 2010 | ||||||
(in thousands) | |||||||
Properties and equipment, net: | |||||||
Natural gas and crude oil properties | |||||||
Proved | $ | 1,599,926 | $ | 1,429,667 | |||
Unproved | 72,663 | 79,053 | |||||
Total natural gas and crude oil properties | 1,672,589 | 1,508,720 | |||||
Pipelines and related facilities | 34,110 | 34,262 | |||||
Transportation and other equipment | 33,209 | 32,410 | |||||
Land, buildings and leasehold improvements | 14,514 | 13,379 | |||||
Construction in progress | 63,351 | 42,128 | |||||
1,817,773 | 1,630,899 | ||||||
Accumulated DD&A | (573,360 | ) | (510,861 | ) | |||
Properties and equipment, net | $ | 1,244,413 | $ | 1,120,038 | |||
June 30, 2011 | December 31, 2010 | ||||||
(in thousands) | |||||||
Senior notes | |||||||
3.25% Convertible senior notes due 2016: | |||||||
Principal amount | $ | 115,000 | $ | 115,000 | |||
Unamortized discount | (18,368 | ) | (20,252 | ) | |||
3.25% Convertible senior notes due 2016, net of discount | 96,632 | 94,748 | |||||
12% Senior notes due 2018: | |||||||
Principal amount | 203,000 | 203,000 | |||||
Unamortized discount | (1,908 | ) | (2,053 | ) | |||
12% Senior notes due 2018, net of discount | 201,092 | 200,947 | |||||
Total senior notes | 297,724 | 295,695 | |||||
Credit facilities | |||||||
Corporate | 8,500 | — | |||||
PDCM | 7,900 | — | |||||
Total credit facilities | 16,400 | — | |||||
Total long-term debt | $ | 314,124 | $ | 295,695 | |||
Amount | |||
(in thousands) | |||
Balance at December 31, 2010 (1) | $ | 28,047 | |
Change in ownership interest of PDCM | (485 | ) | |
Obligations incurred with development activites and assumed with acquisitions | 847 | ||
Accretion expense | 798 | ||
Obligations discharged with disposal of properties and asset retirements | (221 | ) | |
Revisions in estimated cash flows | (322 | ) | |
Balance at June 30, 2011 | 28,664 | ||
Less current portion | (250 | ) | |
Long-term portion | $ | 28,414 | |
For the Twelve Months Ending June 30, | ||||||||||||||||||||||||||
Area | 2012 | 2013 | 2014 | 2015 | 2016 Through Expiration | Total | Expiration Date | |||||||||||||||||||
Volume (MMcf) | ||||||||||||||||||||||||||
Piceance Basin | 32,613 | 32,577 | 28,182 | 22,131 | 60,759 | 176,262 | May 31, 2021 | |||||||||||||||||||
Appalachian Basin (1) | 5,150 | 14,324 | 15,992 | 15,992 | 110,665 | 162,123 | August 31, 2022 | |||||||||||||||||||
NECO | 2,745 | 1,825 | 1,825 | 1,825 | 2,745 | 10,965 | December 31, 2016 | |||||||||||||||||||
Total | 40,508 | 48,726 | 45,999 | 39,948 | 174,169 | 349,350 | ||||||||||||||||||||
Dollar commitment (in thousands) | $ | 19,867 | $ | 24,118 | $ | 22,704 | $ | 19,527 | $ | 82,171 | $ | 168,387 | ||||||||||||||
(1) | Includes a precedent agreement that becomes effective when a planned pipeline is placed in service, currently expected to be September 2012 and represents 8,823 MMcf of the total MMcf presented for the year ending June 30, 2013, 10,629 MMcf for each of the years ending June 30, 2014 and 2015, respectively, and 76,265 MMcf thereafter. This agreement will be null and void if the pipeline is not completed. In August 2009, we issued a letter of credit related to this agreement, see Note 7. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 (1) | 2010 | 2011 (1) | 2010 | |||||||||||||
(in thousands) | ||||||||||||||||
Total stock-based compensation expense | $ | 4,004 | $ | 1,216 | $ | 5,549 | $ | 2,221 | ||||||||
Income tax benefit | (1,521 | ) | (467 | ) | (2,108 | ) | (852 | ) | ||||||||
Net income (loss) impact | $ | 2,483 | $ | 749 | $ | 3,441 | $ | 1,369 | ||||||||
(1) | Includes a total of $2.5 million, pretax, related to a separation agreement with our former chief executive officer. |
Six Months Ended | |||
June 30, 2011 | |||
Expected term of the award | 6 years | ||
Risk-free interest rate | 2.5 | % | |
Volatility | 60.2 | % | |
Weighted average grant date fair value per share | $ | 25.22 |
Number of Shares Underlying SARs | Grant Date Market Price Per Share | Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) | |||||||||||
Outstanding at December 31, 2010 | 57,282 | $ | 24.44 | 9.3 | $ | — | ||||||||
Awarded | 31,552 | 43.95 | 9.7 | — | ||||||||||
Outstanding at June 30, 2011 | 88,834 | 31.37 | 5.3 | 313 | ||||||||||
Vested and expected to vest at June 30, 2011 | 84,851 | 31.27 | 5.0 | 302 | ||||||||||
Exercisable at June 30, 2011 | 48,999 | 29.61 | 2.1 | 197 | ||||||||||
Shares | Weighted Average Grant-Date Fair Value per Share | ||||||
Non-vested at December 31, 2010 | 525,715 | $ | 25.53 | ||||
Granted | 149,365 | 37.42 | |||||
Vested | (183,639 | ) | 28.37 | ||||
Forfeited | (13,580 | ) | 24.51 | ||||
Non-vested at June 30, 2011 | 477,861 | 28.18 | |||||
As of / Six Months Ended | |||
June 30, 2011 | |||
(in thousands, except per share data) | |||
Total intrinsic value of time-based awards vested | $ | 7,185 | |
Total intrinsic value of time-based awards non-vested | 14,293 | ||
Market price per common share | 29.91 |
Six Months Ended | ||||
June 30, 2011 | ||||
Expected term of award | 3 years | |||
Risk-free interest rate | 1.1 | % | ||
Volatility | 74.2 | % | ||
Weighted average grant date fair value per share | $ | 58.53 |
Shares | Weighted Average Grant-Date Fair Value per Share | |||||
Non-vested at December 31, 2010 | 79,550 | $ | 32.52 | |||
Granted | 13,531 | 58.53 | ||||
Vested | (4,109 | ) | 6.47 | |||
Forfeited | (21,927 | ) | 34.32 | |||
Non-vested at June 30, 2011 | 67,045 | 38.78 | ||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||
(in thousands) | |||||||||||
Weighted average common shares outstanding - basic | 23,491 | 19,213 | 23,460 | 19,202 | |||||||
Dilutive effect of share-based compensation: | |||||||||||
Restricted stock | 181 | — | — | 86 | |||||||
SARs | 48 | — | — | — | |||||||
Non employee director deferred compensation | 3 | — | — | 8 | |||||||
Weighted average common and common share equivalents outstanding - diluted | 23,723 | 19,213 | 23,460 | 19,296 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||
(in thousands) | |||||||||||
Weighted average common share equivalents excluded from diluted earnings | |||||||||||
per share due to their anti-dilutive effect: | |||||||||||
Restricted stock | 102 | 434 | 587 | 181 | |||||||
Stock options | 10 | 10 | 10 | 10 | |||||||
SARs | 32 | 57 | 77 | 57 | |||||||
Non employee director deferred compensation | — | 8 | 3 | — | |||||||
Total anti-dilutive common share equivalents | 144 | 509 | 677 | 248 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||
Statement of Operations - Discontinued Operations | 2010 | 2011 | 2010 | |||||||||
(dollars in thousands) | ||||||||||||
Revenues | ||||||||||||
Natural gas, NGL and crude oil sales | $ | 1,995 | $ | 447 | $ | 4,536 | ||||||
Sales from natural gas marketing | 1,136 | — | 2,760 | |||||||||
Well operations, pipeline income and other | 146 | 10 | 402 | |||||||||
Total revenues | 3,277 | 457 | 7,698 | |||||||||
Costs, expenses and other | ||||||||||||
Production costs | 864 | 132 | 1,579 | |||||||||
Cost of natural gas marketing | 1,197 | — | 2,728 | |||||||||
Impairment of proved natural gas and oil properties | 4,506 | — | 4,506 | |||||||||
Depreciation, depletion and amortization | 533 | — | 1,464 | |||||||||
Gain on sale of properties and equipment | — | (3,854 | ) | — | ||||||||
Total costs, expenses and other | 7,100 | (3,722 | ) | 10,277 | ||||||||
Income (loss) from discontinued operations | (3,823 | ) | 4,179 | (2,579 | ) | |||||||
Provision (benefit) for income taxes | (1,510 | ) | 1,559 | (1,063 | ) | |||||||
Income (loss) from discontinued operations, net of tax | $ | (2,313 | ) | $ | 2,620 | $ | (1,516 | ) | ||||
Operational Data | ||||||||||||
Production | ||||||||||||
Natural gas (MMcf) | 354.3 | 8.7 | 722.8 | |||||||||
Crude oil (MBbls) | 10.6 | 3.9 | 22.6 | |||||||||
Natural gas equivalent (MMcfe) | 417.6 | 32.1 | 858.0 |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Statement of Operations Line Item | 2011 | 2010 | 2011 | 2010 | ||||||||||||
(in millions) | ||||||||||||||||
Production costs | $ | 0.6 | $ | 0.9 | $ | 1.5 | $ | 1.9 | ||||||||
Exploration expense | 0.1 | 0.2 | 0.2 | 0.5 | ||||||||||||
General and administrative expense | 0.3 | 0.5 | 0.7 | 1.2 | ||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(in thousands) | |||||||||||||||
Revenues: | |||||||||||||||
Natural gas and crude oil sales | $ | 94,533 | $ | 63,138 | $ | 136,406 | $ | 166,773 | |||||||
Natural gas marketing | 18,897 | 12,588 | 34,099 | 35,275 | |||||||||||
Unallocated | — | (3 | ) | — | — | ||||||||||
Total | $ | 113,430 | $ | 75,723 | $ | 170,505 | $ | 202,048 | |||||||
Segment income (loss) before income taxes: | |||||||||||||||
Natural gas and crude oil sales | $ | 41,235 | $ | 17,206 | $ | 28,325 | $ | 72,860 | |||||||
Natural gas marketing | 690 | 373 | 899 | 730 | |||||||||||
Unallocated | (29,344 | ) | (18,239 | ) | (53,034 | ) | (37,574 | ) | |||||||
Total | $ | 12,581 | $ | (660 | ) | $ | (23,810 | ) | $ | 36,016 | |||||
June 30, 2011 | December 31, 2010 | ||||||
(in thousands) | |||||||
Segment assets: | |||||||
Natural gas and crude oil sales | $ | 1,376,711 | $ | 1,313,805 | |||
Natural gas marketing | 12,688 | 16,338 | |||||
Unallocated | 54,286 | 53,701 | |||||
Assets held for sale | — | 5,191 | |||||
Total | $ | 1,443,685 | $ | 1,389,035 | |||
(in thousands) | |||
Total acquisition cost | $ | 43,015 | |
Recognized amounts of identifiable assets acquired and liabilities assumed: | |||
Assets acquired: | |||
Natural gas and crude oil properties - proved | $ | 39,825 | |
Fair value of derivative instruments, net | 479 | ||
Other assets | 3,369 | ||
Total assets acquired | 43,673 | ||
Liabilities assumed: | |||
Asset retirement obligation | 300 | ||
Other liabilities | 358 | ||
Total liabilities assumed | 658 | ||
Total identifiable net assets acquired | $ | 43,015 | |
2011 Capital Budget | ||||||||||||
Original | Increase | Revised | ||||||||||
(in millions) | ||||||||||||
Developmental drilling | $ | 205 | $ | 88 | $ | 293 | ||||||
Affiliated partnership acquisitions | — | 73 | 73 | |||||||||
Exploration, leasing and other | 28 | 3 | 31 | |||||||||
$ | 233 | $ | 164 | $ | 397 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||
2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||
(dollars in thousands, except per unit data) | |||||||||||||||||||||
Production (1) | |||||||||||||||||||||
Natural gas (MMcf) | 7,513.0 | 6,283.4 | 19.6 | % | 15,260.3 | 12,796.8 | 19.3 | % | |||||||||||||
Crude oil (MBbls) | 426.8 | 320.6 | 33.1 | % | 798.1 | 605.4 | 31.8 | % | |||||||||||||
NGLs (MBbls) | 149.7 | 139.2 | 7.5 | % | 316.6 | 288.2 | 9.9 | % | |||||||||||||
Natural gas equivalent (MMcfe) (2) | 10,972.2 | 9,042.4 | 21.3 | % | 21,948.8 | 18,158.8 | 20.9 | % | |||||||||||||
Average MMcfe per day | 120.6 | 99.4 | 21.3 | % | 121.3 | 100.3 | 20.9 | % | |||||||||||||
Natural Gas, NGL and Crude Oil Sales | |||||||||||||||||||||
Natural gas | $ | 26,501 | $ | 20,415 | 29.8 | % | $ | 50,356 | $ | 51,062 | (1.4 | )% | |||||||||
Crude oil | 40,330 | 23,244 | 73.5 | % | 72,847 | 44,195 | 64.8 | % | |||||||||||||
NGLs | 5,384 | 5,070 | 6.2 | % | 12,891 | 11,299 | 14.1 | % | |||||||||||||
Total natural gas, NGL and crude oil sales | $ | 72,215 | $ | 48,729 | 48.2 | % | $ | 136,094 | $ | 106,556 | 27.7 | % | |||||||||
Realized Gain (Loss) on Derivatives, net (3) | |||||||||||||||||||||
Natural gas | $ | 6,332 | $ | 5,854 | 8.2 | % | $ | 13,231 | $ | 26,733 | (50.5 | )% | |||||||||
Crude oil | (4,529 | ) | 2,039 | * | (7,640 | ) | 4,084 | (287.1 | )% | ||||||||||||
Total realized gain on derivatives, net | $ | 1,803 | $ | 7,893 | (77.2 | )% | $ | 5,591 | $ | 30,817 | (81.9 | )% | |||||||||
Average Sales Price (excluding gain/loss on derivatives) | |||||||||||||||||||||
Natural gas (per Mcf) | $ | 3.53 | $ | 3.25 | 8.6 | % | $ | 3.30 | $ | 3.99 | (17.3 | )% | |||||||||
Crude oil (per Bbl) | 94.50 | 72.49 | 30.4 | % | 91.27 | 73.00 | 25.0 | % | |||||||||||||
NGLs (per Bbl) | 35.94 | 36.43 | (1.3 | )% | 40.71 | 39.21 | 3.8 | % | |||||||||||||
Natural gas equivalent (per Mcfe) | 6.58 | 5.39 | 22.1 | % | 6.20 | 5.87 | 5.6 | % | |||||||||||||
Average Sales Price (including gain/loss on derivatives) | |||||||||||||||||||||
Natural gas (per Mcf) | $ | 4.37 | $ | 4.18 | 4.5 | % | $ | 4.17 | $ | 6.08 | (31.4 | )% | |||||||||
Crude oil (per Bbl) | 83.88 | 78.84 | 6.4 | % | 81.69 | 79.75 | 2.4 | % | |||||||||||||
NGLs (per Bbl) | 35.94 | 36.43 | (1.3 | )% | 40.71 | 39.21 | 3.8 | % | |||||||||||||
Natural gas equivalent (per Mcfe) | 6.75 | 6.26 | 7.8 | % | 6.46 | 7.57 | (14.7 | )% | |||||||||||||
Average Lifting Cost (per Mcfe) (4) | $ | 1.11 | $ | 1.14 | (2.6 | )% | $ | 1.14 | $ | 1.05 | 8.6 | % | |||||||||
Natural Gas Marketing (5) | $ | 690 | $ | 382 | 80.6 | % | $ | 899 | $ | 746 | 20.5 | % | |||||||||
Other Costs and Expenses | |||||||||||||||||||||
Exploration expense | $ | 1,720 | $ | 3,830 | (55.1 | )% | $ | 3,871 | $ | 10,248 | (62.2 | )% | |||||||||
General and administrative expense | 19,509 | 9,855 | 98.0 | % | 33,382 | 20,549 | 62.5 | % | |||||||||||||
Depreciation, depletion and amortization | 32,674 | 26,945 | 21.3 | % | 65,031 | 54,403 | 19.5 | % | |||||||||||||
Interest Expense, net | $ | 9,065 | $ | 7,638 | 18.7 | % | $ | 18,118 | $ | 15,433 | 17.4 | % |
(1) | Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage interest we own. |
(2) | Six Mcf of natural gas equals one Bbl of crude oil or NGL. |
(3) | Represents realized derivative gains and losses related to natural gas and crude oil sales segment, which do not include realized derivative gains and losses related to natural gas marketing. |
(4) | Represents lease operating expenses on a per unit basis. |
(5) | Represents sales from natural gas marketing, net of costs of natural gas marketing, including realized and unrealized derivative gains and losses related to natural gas marketing activities. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
2011 | 2010 | Percentage Change | 2011 | 2010 | Percentage Change | ||||||||||||
Production | |||||||||||||||||
Natural gas (MMcf) | |||||||||||||||||
Rocky Mountain Region | 6,151.2 | 5,693.5 | 8.0 | % | 12,938.7 | 11,566.7 | 11.9 | % | |||||||||
Permian Basin (1) | 101.8 | — | * | 182.9 | — | * | |||||||||||
Appalachian Basin | 1,250.2 | 570.8 | 119.0 | % | 2,117.1 | 1,201.2 | 76.2 | % | |||||||||
Other | 9.8 | 19.1 | (48.7 | )% | 21.6 | 28.9 | (25.3 | )% | |||||||||
Total | 7,513.0 | 6,283.4 | 19.6 | % | 15,260.3 | 12,796.8 | 19.3 | % | |||||||||
Crude oil (MBbls) | |||||||||||||||||
Rocky Mountain Region | 368.4 | 319.5 | 15.3 | % | 688.4 | 603.6 | 14.0 | % | |||||||||
Permian Basin (1) | 56.7 | — | * | 106.8 | — | * | |||||||||||
Appalachian Basin | 1.6 | 1.1 | 45.5 | % | 2.7 | 1.8 | 50.0 | % | |||||||||
Other | 0.1 | — | * | 0.2 | — | * | |||||||||||
Total | 426.8 | 320.6 | 33.1 | % | 798.1 | 605.4 | 31.8 | % | |||||||||
NGLs (MBbls) | |||||||||||||||||
Rocky Mountain Region | 134.4 | 137.1 | (2.0 | )% | 281.9 | 285.0 | (1.1 | )% | |||||||||
Permian Basin (1) | 13.4 | — | * | 31.5 | — | * | |||||||||||
Other | 1.9 | 2.1 | (9.5 | )% | 3.2 | 3.2 | — | % | |||||||||
Total | 149.7 | 139.2 | 7.5 | % | 316.6 | 288.2 | 9.9 | % | |||||||||
Natural gas equivalent (MMcfe) | |||||||||||||||||
Rocky Mountain Region | 9,168.4 | 8,433.1 | 8.7 | % | 18,760.4 | 16,898.6 | 11.0 | % | |||||||||
Permian Basin (1) | 522.2 | — | * | 1,012.9 | — | * | |||||||||||
Appalachian Basin | 1,259.8 | 577.5 | 118.1 | % | 2,133.5 | 1,212.3 | 76.0 | % | |||||||||
Other | 21.8 | 31.8 | (31.4 | )% | 42.0 | 47.9 | (12.3 | )% | |||||||||
Total | 10,972.2 | 9,042.4 | 21.3 | % | 21,948.8 | 18,158.8 | 20.9 | % | |||||||||
(1) | Our Permian Basin properties were acquired in July and November 2010. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||
Average Sales Price (excluding gain/loss on derivatives) | 2011 | 2010 | Percentage Change | 2011 | 2010 | Percentage Change | ||||||||||||||||
Natural gas (per Mcf) (1) | ||||||||||||||||||||||
Rocky Mountain Region | $ | 3.31 | $ | 3.16 | 4.7 | % | $ | 3.11 | $ | 3.91 | (20.5 | )% | ||||||||||
Permian Basin (2) | 2.97 | — | * | 3.97 | — | * | ||||||||||||||||
Appalachian Basin | 4.62 | 4.20 | 10.0 | % | 4.41 | 4.80 | (8.1 | )% | ||||||||||||||
Other | 5.00 | 2.38 | 110.1 | % | 3.67 | 2.66 | 38.0 | % | ||||||||||||||
Weighted average price | 3.53 | 3.25 | 8.6 | % | 3.30 | 3.99 | (17.3 | )% | ||||||||||||||
Crude oil (per Bbl) | ||||||||||||||||||||||
Rocky Mountain Region | 94.39 | 72.49 | 30.2 | % | 92.20 | 72.99 | 26.3 | % | ||||||||||||||
Permian Basin (2) | 95.48 | — | * | 85.58 | — | * | ||||||||||||||||
Appalachian Basin | 83.80 | 72.29 | 15.9 | % | 80.56 | 74.98 | 7.4 | % | ||||||||||||||
Other | 101.41 | — | * | 93.19 | — | * | ||||||||||||||||
Weighted average price | 94.50 | 72.49 | 30.4 | % | 91.27 | 73.00 | 25.0 | % | ||||||||||||||
NGLs (per Bbl) | ||||||||||||||||||||||
Rocky Mountain Region | 33.99 | 36.32 | (6.4 | )% | 39.28 | 39.02 | 0.7 | % | ||||||||||||||
Permian Basin (2) | 55.17 | — | * | 52.46 | — | * | ||||||||||||||||
Other | 38.55 | 43.64 | (11.7 | )% | 51.13 | 56.16 | (9.0 | )% | ||||||||||||||
Weighted average price | 35.94 | 36.43 | (1.3 | )% | 40.71 | 39.21 | 3.8 | % | ||||||||||||||
Natural gas equivalent (per Mcfe) | ||||||||||||||||||||||
Rocky Mountain Region | 6.51 | 5.47 | 19.0 | % | 6.12 | 5.94 | 3.0 | % | ||||||||||||||
Permian Basin | 12.36 | — | * | 11.38 | — | * | ||||||||||||||||
Appalachian Basin | 4.70 | 4.29 | 9.6 | % | 4.48 | 4.87 | (8.0 | )% | ||||||||||||||
Other | 6.05 | 4.32 | 40.0 | % | 6.21 | 5.32 | 16.7 | % | ||||||||||||||
Weighted average price | 6.58 | 5.39 | 22.1 | % | 6.20 | 5.87 | 5.6 | % |
(1) | Our average sales price for natural gas is based on the "net-back" method of accounting for transportation, gathering and processing arrangements with natural gas purchasers. See our revenue recognition policy described in Note 2, Summary of Significant Accounting Policies, to consolidated financial statements in our 2010 Form 10-K and Part 1, Item 2, Financial Condition, Liquidity and Capital Resources - Cash Flows, included in this report. |
(2) | Our Permian Basin properties were acquired in July and November 2010. |
June 30, 2011 | |||||||
Three Months Ended | Six Months Ended | ||||||
(in millions) | |||||||
Increase in production | $ | 12.1 | $ | 25.0 | |||
Increase in average crude oil price | 9.4 | 14.6 | |||||
Increase (decrease) in average NGL price | (0.1 | ) | 0.4 | ||||
Increase (decrease) in average natural gas price | 2.1 | (10.5 | ) | ||||
Total increase in natural gas, NGL and crude oil sales revenue | $ | 23.5 | $ | 29.5 | |||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(in millions) | |||||||||||||||
Lease operating expenses | $ | 12.2 | $ | 10.3 | $ | 25.0 | $ | 19.1 | |||||||
Production taxes | 4.7 | 2.5 | 9.4 | 4.9 | |||||||||||
Costs of well operations and pipeline services | 1.7 | 2.0 | 3.6 | 3.9 | |||||||||||
Overhead and other production expenses | 1.1 | 1.2 | 2.7 | 3.1 | |||||||||||
Total production costs | $ | 19.7 | $ | 16.0 | $ | 40.7 | $ | 31.0 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(in millions) | |||||||||||||||
Commodity price risk management gain (loss), net: | |||||||||||||||
Realized gains (losses): | |||||||||||||||
Natural gas | $ | 6.3 | $ | 5.9 | $ | 13.2 | $ | 26.7 | |||||||
Crude oil | (4.5 | ) | 2.0 | (7.6 | ) | 4.1 | |||||||||
Total realized gains, net | 1.8 | 7.9 | 5.6 | 30.8 | |||||||||||
Unrealized gains (losses): | |||||||||||||||
Reclassification of realized gains included in prior periods unrealized | (0.8 | ) | (7.5 | ) | (6.6 | ) | (21.6 | ) | |||||||
Unrealized gains (losses) for the period | 19.5 | 11.9 | (2.3 | ) | 46.3 | ||||||||||
Total unrealized gains (losses), net | 18.7 | 4.4 | (8.9 | ) | 24.7 | ||||||||||
Total commodity price risk management gain (loss), net | $ | 20.5 | $ | 12.3 | $ | (3.3 | ) | $ | 55.5 | ||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(in millions) | |||||||||||||||
Sales from natural gas marketing | |||||||||||||||
Natural gas sales revenue | $ | 18.4 | $ | 13.3 | $ | 33.5 | $ | 31.5 | |||||||
Realized derivative gain | 0.5 | 1.8 | 1.6 | 2.9 | |||||||||||
Unrealized derivative gain (loss) | — | (2.5 | ) | (1.0 | ) | 0.9 | |||||||||
Total sales from natural gas marketing | 18.9 | 12.6 | 34.1 | 35.3 | |||||||||||
Costs of natural gas marketing | |||||||||||||||
Costs of natural gas purchases | 17.5 | 12.7 | 32.2 | 30.4 | |||||||||||
Realized derivative loss | 0.4 | 1.6 | 1.4 | 2.7 | |||||||||||
Unrealized derivative loss (gain) | 0.1 | (2.4 | ) | (0.9 | ) | 0.9 | |||||||||
Other | 0.2 | 0.3 | 0.5 | 0.5 | |||||||||||
Total costs of natural gas marketing | 18.2 | 12.2 | 33.2 | 34.5 | |||||||||||
Natural gas marketing contribution margin | $ | 0.7 | $ | 0.4 | $ | 0.9 | $ | 0.8 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(in millions) | |||||||||||||||
Amortization of individually insignificant unproved properties | $ | 0.5 | $ | 0.6 | $ | 1.0 | $ | 1.1 | |||||||
Exploratory dry hole costs | 0.1 | 0.6 | 0.2 | 3.5 | |||||||||||
Geological and geophysical costs | — | 0.8 | 0.9 | 1.9 | |||||||||||
Operating, personnel and other | 1.1 | 1.8 | 1.8 | 3.7 | |||||||||||
Total exploration expense | $ | 1.7 | $ | 3.8 | $ | 3.9 | $ | 10.2 | |||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(per Mcfe) | |||||||||||||||
Rocky Mountain Region: | |||||||||||||||
Wattenberg Field | $ | 3.38 | $ | 3.54 | $ | 3.32 | $ | 3.60 | |||||||
Grand Valley Field | 2.48 | 2.47 | 2.51 | 2.46 | |||||||||||
Weighted average | 2.88 | 2.77 | 2.85 | 2.78 | |||||||||||
Permian Basin | 3.98 | — | 3.40 | — | |||||||||||
Appalachian Basin | 1.97 | 2.71 | 2.20 | 2.67 | |||||||||||
Total weighted average | 2.82 | 2.78 | 2.81 | 2.79 |
Gross Drilling Activity | |||||||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||
Productive | In-Process | Productive | In-Process | Productive | In-Process (1) | Productive | In-Process | ||||||||||||||||
Development Wells | |||||||||||||||||||||||
Rocky Mountain Region | 4 | 43 | 24 | 29 | 45 | 50 | 61 | 35 | |||||||||||||||
Permian Basin | 1 | 4 | — | — | 6 | 5 | — | — | |||||||||||||||
Appalachian Basin | — | 4 | — | — | — | 4 | — | — | |||||||||||||||
Total development wells | 5 | 51 | 24 | 29 | 51 | 59 | 61 | 35 | |||||||||||||||
Exploratory Wells | |||||||||||||||||||||||
Rocky Mountain Region | — | — | — | — | — | 1 | — | — | |||||||||||||||
Appalachian Basin | — | — | — | 3 | — | — | 1 | 3 | |||||||||||||||
Total exploratory wells | — | — | — | 3 | — | 1 | 1 | 3 | |||||||||||||||
Total drilling activity | 5 | 51 | 24 | 32 | 51 | 60 | 62 | 38 | |||||||||||||||
Recompletions/refractures | 15 | 5 | 46 | 16 | |||||||||||||||||||
(1) | As of June 30, 2011, a total of 61 wells, including the 59 development wells drilled during the six months ended 2011 and still in-process as of June 30, were waiting to be completed and/or for pipeline connection. |
Net Drilling Activity | |||||||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||
Productive | In-Process | Productive | In-Process | Productive | In-Process | Productive | In-Process | ||||||||||||||||
Development Wells | |||||||||||||||||||||||
Rocky Mountain Region | 3.8 | 30.7 | 19.6 | 22.9 | 33.1 | 35.9 | 53.6 | 27.0 | |||||||||||||||
Permian Basin | 1.0 | 4.0 | — | — | 6.0 | 5.0 | — | — | |||||||||||||||
Appalachian Basin | — | 2.1 | — | — | — | 2.1 | — | — | |||||||||||||||
Total development wells | 4.8 | 36.8 | 19.6 | 22.9 | 39.1 | 43.0 | 53.6 | 27.0 | |||||||||||||||
Exploratory Wells | |||||||||||||||||||||||
Rocky Mountain Region | — | — | — | — | — | 1.0 | — | — | |||||||||||||||
Appalachian Basin | — | — | — | 1.7 | — | — | 0.6 | 1.8 | |||||||||||||||
Total exploratory wells | — | — | — | 1.7 | — | 1.0 | 0.6 | 1.8 | |||||||||||||||
Total drilling activity | 4.8 | 36.8 | 19.6 | 24.6 | 39.1 | 44.0 | 54.2 | 28.8 | |||||||||||||||
Recompletions/refractures | 14.3 | 4.2 | 43.2 | 14.7 | |||||||||||||||||||
Payments due by period | ||||||||||||||||||||
Less than | 1-3 | 3-5 | More than | |||||||||||||||||
Contractual Obligations and Contingent Commitments | Total | 1 year | years | years | 5 years | |||||||||||||||
(in millions) | ||||||||||||||||||||
Long-term liabilities reflected on the consolidated balance sheets (1) | ||||||||||||||||||||
Long-term debt (2) | $ | 334.4 | $ | — | $ | — | $ | 16.4 | $ | 318.0 | ||||||||||
Derivative contracts (3) | 54.5 | 22.3 | 31.8 | 0.4 | — | |||||||||||||||
Derivative contracts - affiliated partnerships (4) | 13.2 | 5.9 | 7.3 | — | — | |||||||||||||||
Production tax liability | 29.8 | 18.5 | 11.3 | — | — | |||||||||||||||
Asset retirement obligations | 28.7 | 0.2 | 0.4 | 0.8 | 27.3 | |||||||||||||||
Other liabilities (5) | 10.1 | 0.3 | 3.8 | 0.6 | 5.4 | |||||||||||||||
470.7 | 47.2 | 54.6 | 18.2 | 350.7 | ||||||||||||||||
Commitments, contingencies and other arrangements (6) | ||||||||||||||||||||
Interest on long-term debt (7) | 189.6 | 30.8 | 60.8 | 58.4 | 39.6 | |||||||||||||||
Operating leases | 9.0 | 2.2 | 3.5 | 2.3 | 1.0 | |||||||||||||||
Rig commitment (8) | 4.5 | 3.4 | 1.1 | — | — | |||||||||||||||
Drilling commitment | 0.9 | — | — | — | 0.9 | |||||||||||||||
Firm transportation and processing agreements (9) | 168.4 | 19.9 | 46.8 | 36.4 | 65.3 | |||||||||||||||
Other | 0.5 | 0.1 | 0.3 | 0.1 | — | |||||||||||||||
372.9 | 56.4 | 112.5 | 97.2 | 106.8 | ||||||||||||||||
Total | $ | 843.6 | $ | 103.6 | $ | 167.1 | $ | 115.4 | $ | 457.5 | ||||||||||
(1) | Table does not include deferred income tax liability to taxing authorities of $179.7 million, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. |
(2) | Amount presented does not agree with the balance sheet in that the amount above excludes $20.3 million in unamortized debt discount. See Note 7, Long-Term Debt, to the accompanying condensed consolidated financial statements included in this report. |
(3) | Represents our gross liability related to the fair value of derivative positions, including the fair value of derivative contracts we entered into on behalf of our affiliated partnerships as the managing general partner. We have a related receivable from the partnerships of $9.5 million. |
(4) | Represents our affiliated partnerships' designated portion of the fair value of our gross derivative assets. |
(5) | Includes funds held from revenue distribution to third party investors for plugging liabilities related to wells we operate and deferred officer compensation. |
(6) | Table does not include an undrawn $18.7 million irrevocable standby letter of credit pending issuance to a transportation service provider; see Note 7, Long-Term Debt, in the accompanying condensed consolidated financial statements included in this report. Additionally, the table does not include the annual repurchase obligations to investing partners of our affiliated partnerships or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations; see Note 9, Commitments and Contingencies - Partnership Repurchase Provision; Employment Agreements with Executive Officers, to the accompanying condensed consolidated financial statements included in this report. |
(7) | Amounts presented include $18.2 million payable to the holders of our 3.25% convertible senior notes due 2016 and $161.4 million to the holders of our 12% senior notes due 2018. Amounts also include $9.0 million payable to the participating banks of our revolving credit facility, of which interest of $7.0 million due on the unutilized commitment at a rate of 0.5% per annum, $1.6 million related to the outstanding balance of $8.5 million on our corporate credit facility and $0.4 million related to the undrawn $18.7 million letter of credit at a rate of 2.2% per annum. |
(8) | Drilling rig commitment in the above table reflects our proportionate share of the maximum obligation for the services of one drilling rig in the Appalachian Basin. |
(9) | Represents our gross commitment, including our proportionate share of PDCM. We will recognize in our financial statements our proportionate share based on our working interest; however, the costs of all volume shortfalls will be borne by PDC only. See Note 9, Commitments and Contingencies - Firm Transportation Agreements, to the accompanying condensed consolidated financial statements included in this report. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(in millions) | |||||||||||||||
Adjusted cash flows from operations: | |||||||||||||||
Adjusted cash flows from operations | $ | 34.1 | $ | 28.8 | $ | 60.2 | $ | 78.2 | |||||||
Changes in assets and liabilities | 22.0 | 15.2 | 11.4 | 17.2 | |||||||||||
Net cash provided by operating activities | $ | 56.1 | $ | 44.0 | $ | 71.6 | $ | 95.4 | |||||||
Adjusted net income (loss) attributable to shareholders: | |||||||||||||||
Adjusted net income (loss) attributable to shareholders | $ | (2.4 | ) | $ | (5.3 | ) | $ | (5.2 | ) | $ | 5.6 | ||||
Unrealized gain (loss) on derivatives, net | 18.7 | 4.2 | (9.1 | ) | 24.7 | ||||||||||
Tax effect of above adjustments | (7.1 | ) | (1.6 | ) | 3.5 | (9.3 | ) | ||||||||
Net income (loss) attributable to shareholders | $ | 9.2 | $ | (2.7 | ) | $ | (10.8 | ) | $ | 21.0 | |||||
Adjusted EBITDA: | |||||||||||||||
Adjusted EBITDA | $ | 35.7 | $ | 26.5 | $ | 72.5 | $ | 80.1 | |||||||
Unrealized gain (loss) on derivatives, net | 18.7 | 4.2 | (9.1 | ) | 24.7 | ||||||||||
Interest expense, net | (9.1 | ) | (7.6 | ) | (18.1 | ) | (15.4 | ) | |||||||
Income tax benefit (expense) | (3.4 | ) | 1.7 | 8.9 | (12.5 | ) | |||||||||
Depreciation, depletion and amortization | (32.7 | ) | (27.5 | ) | (65.0 | ) | (55.9 | ) | |||||||
Net income (loss) attributable to shareholders | $ | 9.2 | $ | (2.7 | ) | $ | (10.8 | ) | $ | 21.0 | |||||
• | For natural gas and crude oil sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also |
• | For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. |
Floors | Collars | Fixed-Price Swaps | CIG Basis Protection Swaps | |||||||||||||||||||||||||||||||||
Commodity/ Index/ Maturity Period | Quantity (Oil - MBbls) | Weighted Average Contract Price | Quantity (Gas - BBtu (1) Oil - MBbls) | Weighted Average Contract Price | Quantity (Gas - BBtu (1) Oil - MBbls) | Weighted Average Contract Price | Quantity (BBtu) (1) | Weighted Average Contract Price | Fair Value June 30, 2011 (2) (in thousands) | |||||||||||||||||||||||||||
Floors | Ceilings | |||||||||||||||||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||||||||
NYMEX | ||||||||||||||||||||||||||||||||||||
2011 | — | $ | — | — | $ | — | $ | — | 6,720.2 | $ | 6.71 | 5,394.4 | $ | (1.82 | ) | $ | 7,227 | |||||||||||||||||||
2012 | — | — | 4,885.7 | 6.00 | 8.27 | 7,906.6 | 6.58 | 9,861.2 | (1.81 | ) | 6,674 | |||||||||||||||||||||||||
2013 | — | — | 4,438.0 | 6.10 | 8.60 | 6,204.8 | 6.82 | 8,903.2 | (1.81 | ) | 3,872 | |||||||||||||||||||||||||
2014 | — | — | — | — | — | 758.4 | 5.49 | — | — | 50 | ||||||||||||||||||||||||||
CIG | ||||||||||||||||||||||||||||||||||||
2011 | — | — | — | — | — | 2,661.8 | 4.41 | — | — | 578 | ||||||||||||||||||||||||||
2012 | — | — | — | — | — | 700.0 | 4.11 | — | — | (243 | ) | |||||||||||||||||||||||||
2013 | — | — | 235.0 | 4.00 | 5.45 | — | — | — | — | (26 | ) | |||||||||||||||||||||||||
2014 | — | — | 1,115.0 | 4.50 | 5.67 | — | — | — | — | (23 | ) | |||||||||||||||||||||||||
2015 | — | — | 1,040.0 | 4.50 | 5.67 | — | — | — | — | (230 | ) | |||||||||||||||||||||||||
PEPL | ||||||||||||||||||||||||||||||||||||
2011 | — | — | — | — | — | 1,773.8 | 5.60 | — | — | 2,309 | ||||||||||||||||||||||||||
2012 | — | — | — | — | — | 1,355.8 | 6.18 | — | — | 2,138 | ||||||||||||||||||||||||||
2013 | — | — | — | — | — | 990.4 | 6.18 | — | — | 1,309 | ||||||||||||||||||||||||||
Total Natural Gas | — | 11,713.7 | 29,071.8 | 24,158.8 | 23,635 | |||||||||||||||||||||||||||||||
Crude Oil | ||||||||||||||||||||||||||||||||||||
NYMEX | ||||||||||||||||||||||||||||||||||||
2011 | 113.0 | 78.41 | 172.4 | 79.85 | 104.78 | 373.0 | 82.64 | — | — | (5,877 | ) | |||||||||||||||||||||||||
2012 | 36.0 | 65.38 | 643.6 | 81.41 | 106.28 | 444.0 | 91.27 | — | — | (6,222 | ) | |||||||||||||||||||||||||
2013 | — | — | 317.6 | 75.00 | 104.30 | 186.9 | 84.15 | — | — | (5,388 | ) | |||||||||||||||||||||||||
2014 | — | — | 36.0 | 90.00 | 106.15 | — | — | — | — | (81 | ) | |||||||||||||||||||||||||
2015 | — | — | 36.0 | 90.00 | 106.15 | — | — | — | — | (76 | ) | |||||||||||||||||||||||||
Total Crude Oil | 149.0 | 1,205.6 | 1,003.9 | — | (17,644 | ) | ||||||||||||||||||||||||||||||
Total Natural Gas and Crude Oil | $ | 5,991 | ||||||||||||||||||||||||||||||||||
(1 | ) | A standard unit of measurement for natural gas (one BBtu equals one MMcf). |
(2 | ) | Approximately 20.6% of the fair value of our derivative assets and 12.4% of our derivative liabilities were measured using significant unobservable inputs (Level 3); see Note 3, Fair Value Measurements and Disclosures, to the accompanying condensed consolidated financial statements. |
Fixed-Price Swaps | NYMEX Basis Protection Swaps | |||||||||||||||||
Commodity/ Derivative Instrument/ Maturity Period | Quantity (BBtu)(1) | Weighted Average Contract Price | Quantity (BBtu)(1) | Weighted Average Contract Price | Fair Value June 30, 2011 (2) (in thousands) | |||||||||||||
Natural Gas | ||||||||||||||||||
Sales | ||||||||||||||||||
Physical | ||||||||||||||||||
2011 | 4.7 | $ | 5.66 | 31.1 | $ | 0.94 | $ | 25 | ||||||||||
2012 | 1.4 | 5.85 | 55.1 | 0.95 | 36 | |||||||||||||
Financial | ||||||||||||||||||
2011 | 938.8 | 5.24 | 128.8 | 0.07 | 714 | |||||||||||||
2012 | 871.6 | 4.87 | 227.6 | 0.07 | 49 | |||||||||||||
2013 | 90.0 | 5.00 | — | — | (23 | ) | ||||||||||||
Purchases | ||||||||||||||||||
Physical | ||||||||||||||||||
2011 | 938.2 | 5.23 | — | — | (586 | ) | ||||||||||||
2012 | 870.4 | 4.85 | — | — | 43 | |||||||||||||
2013 | 90.0 | 4.99 | — | — | 26 | |||||||||||||
Financial | ||||||||||||||||||
2011 | 4.0 | 4.55 | 12.6 | 0.13 | (1 | ) | ||||||||||||
2012 | 1.4 | 4.87 | 30.4 | 0.13 | (2 | ) | ||||||||||||
Total Natural Gas | 3,810.5 | 485.6 | $ | 281 | ||||||||||||||
(1 | ) | A standard unit of measurement for natural gas (one BBtu equals one MMcf). |
(2 | ) | Approximately 5.8% of the fair value of our derivative assets were measured using significant unobservable inputs (Level 3); see Note 3, Fair Value Measurements and Disclosures, to the accompanying condensed consolidated financial statements. |
Six Months Ended | Year Ended | ||||||
June 30, 2011 | December 31, 2010 | ||||||
Average Index Closing Price | |||||||
Natural Gas (per MMBtu) | |||||||
CIG | $ | 3.90 | $ | 3.92 | |||
NYMEX | 4.21 | 4.39 | |||||
Crude Oil (per Bbl) | |||||||
NYMEX | 97.15 | 77.32 | |||||
Average Sales Price Realized | |||||||
Excluding realized derivative gains/(losses) | |||||||
Natural Gas (per Mcf) | $ | 3.30 | $ | 3.61 | |||
Crude Oil (per Bbl) | 91.27 | 74.03 | |||||
Including realized derivative gains/(losses) | |||||||
Natural Gas (per Mcf) | 4.17 | 5.12 | |||||
Crude Oil (per Bbl) | 81.69 | 79.62 |
Period | Total Number of Shares Purchased (1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs | |||||||||
April 1 - 30, 2011 | 13,265 | $ | 40.19 | — | — | ||||||||
May 1 - 31, 2011 | 13,496 | 39.76 | — | — | |||||||||
June 1 - 30, 2011 | — | — | — | — | |||||||||
Total | 26,761 | 39.98 | |||||||||||
(1) | Purchases represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. |
Incorporated by Reference | ||||||||||||
Exhibit | SEC File | Filed | ||||||||||
Number | Exhibit Description | Form | Number | Exhibit | Filing Date | Herewith | ||||||
10.1 * | Separation Agreement and General Release by and between Richard W. McCullough and Petroleum Development Corporation, effective as of July 14, 2011. | 8-K | 000-07246 | 10.1 | 7/18/2011 | |||||||
10.2 † | First Amendment to the Gas Purchase Agreement between Williams Production RMT Company LLC, Riley Natural Gas Company and Petroleum Development Corporation, executed July 27, 2011, dated and effective as of June 1, 2011. | 8-K | 000-07246 | 10.1 | 8/2/2011 | |||||||
12.1 | Computation of Ratio of Earnings to Fixed Charges. | X | ||||||||||
31.1 | Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
31.2 | Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
32.1 | Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. | X | ||||||||||
*Management contract or compensatory plan or arrangement. | ||||||||||||
† Confidential portions of this document have been omitted and will be filed separately with the SEC pursuant to Rule 24b-2 under the Exchange Act. |
Petroleum Development Corporation | |
(Registrant) | |
Date: August 4, 2011 | /s/ James M. Trimble |
James M. Trimble, | |
President and Chief Executive Officer | |
(principal executive officer) | |
/s/ Gysle R. Shellum | |
Gysle R. Shellum | |
Chief Financial Officer | |
(principal financial officer) | |
/s/ R. Scott Meyers | |
R. Scott Meyers | |
Chief Accounting Officer | |
(principal accounting officer) |
Exhibit 12.1 | ||||||||||||||||||||||||
PETROLEUM DEVELOPMENT CORPORATION | ||||||||||||||||||||||||
Statement of Computation of Ratio of Earnings to Fixed Charges | ||||||||||||||||||||||||
Six Months | ||||||||||||||||||||||||
Ended | ||||||||||||||||||||||||
June 30, | Year Ended December 31, | |||||||||||||||||||||||
2011 | 2010 | 2009 | 2008 | 2007 (d) | 2006 (d) | |||||||||||||||||||
(dollars in thousands) | ||||||||||||||||||||||||
Earnings | ||||||||||||||||||||||||
Income (loss ) from continuing operations before income taxes | $ | (23,810 | ) | $ | 8,113 | $ | (125,172 | ) | $ | 163,168 | $ | 42,590 | $ | 379,800 | ||||||||||
Fixed charges (see below) | 19,874 | 35,197 | 39,403 | 31,629 | 12,796 | 4,187 | ||||||||||||||||||
Amortization of capitalized interest | 365 | 788 | 991 | 744 | 366 | 52 | ||||||||||||||||||
Interest capitalized | (590 | ) | (301 | ) | (751 | ) | (2,618 | ) | (3,023 | ) | (1,620 | ) | ||||||||||||
Total adjusted earnings (loss) available for fixed charges | $ | (4,161 | ) | $ | 43,797 | $ | (85,529 | ) | $ | 192,923 | $ | 52,729 | $ | 382,419 | ||||||||||
Fixed Charges | ||||||||||||||||||||||||
Interest and debt expense (a) | $ | 18,129 | $ | 33,250 | $ | 37,208 | $ | 28,132 | $ | 9,279 | $ | 2,443 | ||||||||||||
Interest capitalized | 590 | 301 | 751 | 2,618 | 3,023 | 1,620 | ||||||||||||||||||
Interest component of rental expense (b) | 1,155 | 1,646 | 1,444 | 879 | 494 | 124 | ||||||||||||||||||
Total fixed charges | $ | 19,874 | $ | 35,197 | $ | 39,403 | $ | 31,629 | $ | 12,796 | $ | 4,187 | ||||||||||||
Ratio of Earnings to Fixed Charges | — | (c) | 1.2x | — | (c) | 6.1x | 4.1x | 91.3x | ||||||||||||||||
(a) | Represents interest expense on long-term debt and amortization of debt discount and issuance costs. |
(b) | Represents the portion of rental expense which we believe represents an interest component. |
(c) | For the six months ended June 30, 2011, and the year ended December 31, 2009, earning were insufficient to cover total fixed charges by $24.0 million and $124.9 million, respectively. |
(d) | Total adjusted earnings available for fixed charges for the years ended December 31, 2006 through 2007 do not present the effects of the divestitures of our Michigan and North Dakota assets as discontinued operations as the amounts related to these operations were immaterial to these years. |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditor and the audit committee of the registrant's board of directors (or persons performing the equivalent functions); |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: | August 4, 2011 | /s/ James M. Trimble | |
James M. Trimble | |||
Chief Executive Officer |
1. | I have reviewed this Quarterly Report on Form 10-Q of Petroleum Development Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditor and the audit committee of the registrant's board of directors (or persons performing the equivalent functions); |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: | August 4, 2011 | /s/ Gysle R. Shellum | |
Gysle R. Shellum | |||
Chief Financial Officer |
1. | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ James M. Trimble | August 4, 2011 | |
James M. Trimble | ||
President and Chief Executive Officer | ||
/s/ Gysle R. Shellum | August 4, 2011 | |
Gysle R. Shellum | ||
Chief Financial Officer |
Balance Sheet Parentheticals (USD $)
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Jun. 30, 2011
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Dec. 31, 2010
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Shareholders' Equity: | Â | Â |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, shares issued | 23,565,040 | 23,462,326 |
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred stock, shares issued | 0 | 0 |
Treasury shares, at cost | 6,238 | 2,938 |
Document and Entity Information Document
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6 Months Ended | |
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Jun. 30, 2011
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Jul. 22, 2011
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Entity Information [Line Items] | Â | Â |
Entity Registrant Name | PETROLEUM DEVELOPMENT CORP | Â |
Entity Central Index Key | 0000077877 | Â |
Current Fiscal Year End Date | --12-31 | Â |
Entity Filer Category | Accelerated Filer | Â |
Document Type | 10-Q | Â |
Document Period End Date | Jun. 30, 2011 | |
Document Fiscal Year Focus | 2011 | Â |
Document Fiscal Period Focus | Q2 | Â |
Amendment Flag | false | Â |
Entity Common Stock, Shares Outstanding | Â | 23,590,922 |
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LONG-TERM DEBT
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Jun. 30, 2011
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Long-term Debt, Unclassified [Abstract] | Â | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Text Block] | LONG-TERM DEBT Long-term debt consists of the following:
Senior Notes 3.25% Convertible Senior Notes Due 2016. In November 2010, we issued $115 million of 3.25% convertible senior notes due 2016 in a private placement. The maturity for the payment of principal is May 15, 2016. Interest at the rate of 3.25% per year is payable in cash semiannually in arrears on each May 15 and November 15, which commenced on May 15, 2011. We allocated the gross proceeds of the convertible notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, with similar terms and priced on the same day we issued our convertible notes. The original issue discount and the deferred note issuance costs are being amortized to interest expense over the term of the debt using an effective interest rate of 7.4%. Upon conversion, the convertible notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the $1,000 principal amount of the convertible notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. 12% Senior Notes Due 2018. In 2008, we issued $203 million of 12% senior notes due 2018 in a private placement. The maturity for the payment of principal is February 15, 2018. Interest at the rate of 12% per year is payable in cash semiannually in arrears on each February 15 and August 15. The senior notes were issued at a discount, 98.572% of the principal amount. The indenture governing the notes contains customary representations and warranties as well as typical restrictive covenants. The original issue discount and the deferred note issuance costs are being amortized to interest expense over the term of the debt using the effective interest method. We were in compliance with all covenants related to our senior notes as of June 30, 2011, and expect to remain in compliance throughout the next twelve-month period. Bank Credit Facilities Corporate Bank Credit Facility. We operate under a credit facility dated as of November 5, 2010, as amended last on May 6, 2011, with an aggregate revolving commitment or borrowing base of $350 million. The maximum allowable facility amount is $600 million. The credit facility is with certain commercial lending institutions and is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. Our credit facility borrowing base is subject to size redetermination semiannually based on a valuation of our natural gas and crude oil reserves at December 31 and June 30 and is also subject to a redetermination upon the occurrence of certain events. The borrowing base of the credit facility will be the loan value assigned to the proved reserves attributable to our natural gas and crude oil interests, excluding proved reserves attributable to PDCM and our 26 affiliated partnerships. The credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing natural gas and crude oil properties and substantially all of our other assets. Neither PDCM nor the various limited partnerships that we have sponsored and continue to serve as the managing general partner are guarantors of the credit facility. Our outstanding principal amount accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires on November 5, 2015, or in the event that the borrowing base would fall below the outstanding balance. The credit facility contains covenants customary for agreements of this type. Through May 26, 2011, we had outstanding an undrawn $18.7 million irrevocable standby letter of credit in favor of a third party transportation service provider. This letter of credit reduced the amount of available funds under our credit facility by an equal amount. We paid a fronting fee of 0.125% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans (2.0% per annum as of May 26, 2011) for the period the letter of credit remained outstanding. The letter of credit was originally set to expire on May 22, 2012. On May 27, 2011, we were required to replace the original letter of credit with a new letter of credit. As of June 30, 2011, for administrative reasons, the new letter of credit was not yet final; however, it was completed and outstanding as of July 25, 2011, and therefore has been included in this report as if outstanding, but undrawn, for available liquidity calculations as of June 30, 2011. There were no significant changes from the original letter of credit. As of June 30, 2011, we had drawn $8.5 million from our credit facility compared to no outstanding draws as of December 31, 2010. We pay a fee of 0.5% per annum on the unutilized commitment on the available funds under our credit facility. As of June 30, 2011, the available funds under our credit facility, assuming the $18.7 million irrevocable standby letter of credit was in effect, were $322.8 million. The weighted average borrowing rate on our credit facility was 0.7% per annum as of June 30, 2011. PDCM Credit Facility. PDCM has a credit facility dated as of April 30, 2010, as amended on April 20, 2011, with an aggregate revolving commitment or borrowing base of $40 million. In addition to the increase in borrowing base, the first amendment permits PDCM to enter into swap agreements on new properties which were not included in the most recent reserve report and which have been producing for at least 30 days. The credit facility is subject to and secured by PDCM's properties, including our proportionate share of such properties. The credit facility borrowing base is subject to size redetermination semiannually based upon a valuation of PDCM's reserves at December 31 and June 30; further, either PDCM or the lenders may request a redetermination upon the occurrence of certain events. Pursuant to the interests of the joint venture, the credit facility will be utilized by PDCM for the exploration and development of its Appalachian assets. As of June 30, 2011, PDCM had drawn $15 million from its credit facility, of which our proportionate share was $7.9 million. As of December 31, 2010, there were no amounts outstanding related to this credit facility. The weighted average borrowing rate on PDCM's credit facility was 1.8% per annum as of June 30, 2011. As of June 30, 2011, both the Company and PDCM were in compliance with all bank credit facility covenants and expect to remain in compliance throughout the next twelve-month period. |
DIVESTITURES AND DISCONTINUED OPERATIONS
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Jun. 30, 2011
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DIVESTITURE AND DISCONTINUED OPERATIONS [Abstract] | Â | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block] | DIVESTITURES AND DISCONTINUED OPERATIONS North Dakota. During the fourth quarter of 2010, we developed a plan to divest our North Dakota assets. The plan included 100% of our North Dakota assets, consisting of producing wells, undeveloped leaseholds and related facilities primarily located in Burke County. The plan received our Board of Directors' (the "Board") approval and, in December 2010, we effected a letter of intent with an unrelated third party. Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the North Dakota assets were reclassified as held for sale as of December 31, 2010, and the results of operations related to those assets have been separately reported as discontinued operations in the accompanying financial statements for all periods presented. In February 2011, we executed a purchase and sale agreement and subsequently closed with the same unrelated party. Proceeds from the sale were $9.5 million, net of non-affiliated investor partners' share of $3.8 million, resulting in a pretax gain on sale of $3.9 million. Selected financial information related to divested and discontinued operations. The table below presents selected operational information related to discontinued operations. While the reclassification of revenues and expenses related to discontinued operations for prior period had no impact upon previously reported net earnings, the statement of operations and operational data present the revenues, expenses and production volumes that were reclassified from the specified statement of operations line items to discontinued operations. The following table presents statement of operations data related to our discontinued operations. There was no activity recorded for discontinued operations for the three months ended 2011. The three and six months ended 2010, in addition to the discontinued operations data of our North Dakota assets, includes operations data related to the July 2010 divestiture of our Michigan assets.
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FAIR VALUE MEASUREMENTS AND DISCLOSURES
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FAIR VALUE OF FINANCIAL INSTRUMENTS [Abstract] | Â | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value, Measurement Inputs, Disclosure [Text Block] | FAIR VALUE MEASUREMENTS AND DISCLOSURES Derivative Financial Instruments Determination of fair value. Fair value accounting standards have established a fair value hierarchy that prioritizes the inputs used in applying a valuation methodology. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means. Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets, both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. The counterparties to our derivative instruments are primarily financial institutions who are also major lenders in our credit facility agreement. We validate our fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value. The following table presents, for each hierarchy level, our derivative assets and liabilities, both current and non-current portions, including the derivative assets and liabilities designated to our affiliated partnerships and our proportionate share of PDCM's derivative assets and liabilities, measured at fair value on a recurring basis.
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The following table presents a reconciliation of our Level 3 fair value measurements.
__________
See Note 4 for additional disclosure related to our derivative financial instruments. Non-Derivative Financial Assets and Liabilities The carrying values of the financial instruments comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. As of June 30, 2011, and December 31, 2010, the liability related to this plan was $0.1 million, which was included in other liabilities on the balance sheet. The portion of our long-term debt related to our corporate credit facility, as well as our proportionate share of PDCM's credit facility, approximates fair value due to the variable nature of its related interest rate. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, as of June 30, 2011, we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2015 to be $111.7 million or 97.1% of par value and the portion related to our 12% senior notes due 2018 to be $226.3 million or 111.5% of par value. We determined these valuations based upon measurements of broker/dealer quotes and trading activity, respectively. |
COMMITMENTS AND CONTINGENCIES
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COMMITMENTS AND CONTINGENCIES [Abstract] | Â | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Text Block] | COMMITMENTS AND CONTINGENCIES Merger Agreements. On June 20, 2011, pursuant to our previously announced partnership acquisition plan, we entered into separate merger agreements with five of our affiliated partnerships: PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-C Limited Partnership, PDC 2003-D Limited Partnership and PDC 2002-D Limited Partnership (collectively, the "2003/2002-D Partnerships"). We serve as the managing general partner of each of the 2003/2002-D Partnerships. Pursuant to each merger agreement, if the merger is approved by the holders of a majority of the limited partnership units held by limited partners of that partnership not owned by us (the "non-affiliated investor partners"), as well as the satisfaction of other customary closing conditions, then we will acquire such partnerships. If all five partnerships are acquired, we expect to pay an aggregate of approximately $29.5 million to the non-affiliated investor partners for the limited partnership units of these partnerships. On June 23, 2011, we filed the preliminary proxy statements with the SEC and anticipate, upon clearance by the SEC, that the definitive proxy statements are anticipated to be mailed to investors in August 2011. If the required approvals are received, we expect the mergers to be completed in the fourth quarter of 2011. We expect to finance the acquisition of the 2003/2002-D Partnerships by borrowing funds under our revolving credit facility. There can be no assurance that we will be successful in the acquisition of the 2003/2002-D Partnerships, individually or collectively, or on terms acceptable to us. Drilling Rig Contract. In order to secure the services of a drilling rig, in August 2010, PDCM entered into a commitment with a drilling contractor for the services of a drilling rig. The commitment expires in October 2012. During the first quarter of 2011, included in production costs in the statement of operations, we recorded a charge of $0.5 million related to our proportionate share of rig laydown costs. As of June 30, 2011, our proportionate share of PDCM's related maximum commitment through October 2012 was $4.5 million. Firm Transportation Agreements. We have entered into contracts that provide firm transportation, sales and processing charges on pipeline systems through which we transport or sell our natural gas and the natural gas of working interest owners, PDCM, our affiliated partnerships and other third parties. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. Satisfaction of the volume requirements includes volumes produced by us, volumes purchased from third parties and volumes produced by our joint venture and affiliated partnerships. We record in our financial statements only our share of costs based upon our working interest in the wells; however, the costs of all volume shortfalls will be borne by PDC. As of June 30, 2011, we have a liability in the amount of $3.1 million included in other liabilities on the balance sheet related to an agreement in the Piceance Basin. On July 27, 2011, we entered into an amendment with the unrelated third party subject to this agreement and as a result, the accrued liability as of June 30, 2011, will be reduced during the third quarter of 2011 with no cash payment by us required. The amendment did not extend the expiration date of the original agreement. The table below does not include the impact of this amendment. Including the impact of this amendment, our volume requirements for the Piceance Basin would be 18,000 MMcf, 19,814 MMcf, 39,252 MMcf, 33,201 MMcf and 126,265 MMcf for the 12 months ending June 30, 2012, 2013, 2014, 2015 and 2016 through expiration, respectively, for a total of 236,532 MMcf. The following table presents gross volume information, including our proportionate share of PDCM, related to our long-term firm sales, processing and transportation agreements for pipeline capacity.
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Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There are no assurances that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. Royalty Owner Class Action Gobel et al v. Petroleum Development Corporation, filed on January 27, 2009, in Circuit Court of Harrison County, CA No. 09-C-40-2 David W. Gobel, individually and allegedly as representative of all royalty owners in the Company's West Virginia oil and gas wells, filed a lawsuit against the Company alleging that we failed to properly pay royalties. The allegations stated that the Company improperly deducted certain charges and costs before applying the royalty percentage. Punitive damages were requested in addition to breach of contract, tort and fraud allegations. On October 27, 2010, the state court set a trial date of April 2012. In April 2011, the Company entered into an oral settlement agreement with respect to this lawsuit, settling all claims between the parties for an aggregate payment of $8.7 million. On June 15, 2011, a written settlement agreement was signed confirming these terms and on June 30, 2011, the state court granted initial approval of the settlement agreement, subject to notice to class members and final court approval. As of June 30, 2011, the total settlement amount of $8.7 million was accrued and included in other accrued expenses on the accompanying balance sheet. A related escrow account was fully funded on July 22, 2011. Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures in place to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. As of June 30, 2011, and December 31, 2010, we had accrued environmental liabilities in the amount of $2.3 million and $1.7 million, respectively, included in other accrued expenses on the balance sheet. We are not currently aware of any environmental claims existing as of June 30, 2011, which have not been provided for or would otherwise have a material impact on our accompanying financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on our properties. Partnership Repurchase Provision. Substantially all of our drilling programs contain a repurchase provision where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the respective partnership's first cash distribution. The provision provides that we are obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions from production), if repurchase is requested by investors, subject to our financial ability to do so. As of June 30, 2011, the maximum annual repurchase obligation, based upon the minimum price described above, was approximately $5 million. We believe we have adequate liquidity to meet this obligation. For the six months ended 2011, amounts paid for the repurchase of partnership units pursuant to this provision were immaterial. Employment Agreements with Executive Officers. With the exception of our Chief Executive Officer, we have employment agreements with our executive officers. The employment agreements provide for annual base salaries, eligibility for performance bonus compensation and other various benefits, including severance benefits. We are currently in the process of preparing an employment agreement with our Chief Executive Officer. If, within two years following a change of control of the Company ("change in control period"), either the Company terminates the executive officer without cause or the executive officer terminates employment for good reason (what is referred to as a "double trigger"), then the severance benefits owed equals three times the sum of the executive's highest annual base salary during the previous two years of employment immediately preceding the termination date and the executive's highest annual bonus paid or, in the case of one executive officer, paid or payable during the same two-year period. For one executive, in this calculation, the target bonus will be used as the minimum value for the first two years of employment. Where the Company terminates the executive officer without cause or the executive officer terminates employment for good reason outside of the change in control period, the severance benefits range from two times to three times, specific to the executive officer, the benefits noted above. For this purpose, a change of control and good reason correspond to the respective definitions of change of control and good reason under Internal Revenue Code ("IRC") 409A and the supporting Treasury regulations, with some differences. Under any of the above circumstances, the executive officer is also entitled under his employment agreement to (i) vesting of any unvested equity compensation (excluding all long-term incentive shares), (ii) reimbursement for any unpaid expenses, (iii) retirement benefits earned under the current and/or previous agreements, (iv) continued coverage under our medical plan at the Company's cost for the federal COBRA health continuation coverage period and (v) payment of any earned and unpaid bonus amounts. In addition, the executive officer is entitled to receive any benefits that he would have otherwise been entitled to receive under our qualified retirement plan, although those benefits are not increased or accelerated. In the event that an executive officer is terminated for just cause, we are required to pay the executive officer his base salary through the termination date plus a partial year bonus, incentive, deferred, retirement or other compensation and to provide any other benefits, which have been earned or become payable as of the termination date. In the event that an executive officer voluntarily terminates his employment for other than good reason, he is entitled to receive (i) his base salary and bonus, provided, however, that with respect to the bonus, for certain executive officers, there will be no proration of the bonus if such executive leaves prior to the last day of the year and, with respect to one executive officer, there will be no proration of the bonus in the event such executive officer leaves prior to March 31 in the year of his termination, (ii) any incentive, deferred or other compensation which has been earned or has become payable, but which has not yet been paid under the schedule originally contemplated in the agreement under which they were granted, (iii) any unpaid expense reimbursement and (iv) any other payments for benefits earned under the employment agreement or our plans. In the event of death or disability, the executive is entitled to receive certain benefits. For this purpose, the definition of "disability" corresponds to the definition under IRC 409A and the supporting Treasury regulations. The benefits will (i) in the case of death be paid in a lump sum and be equal to the base salary that would otherwise have been paid for a six-month period following the termination date and (ii) in the case of disability be up to thirteen weeks of ongoing base salary plus a lump sum equal to six months of base salary. See Note 13 for a discussion related to the separation agreement entered into with our former chief executive officer during the three months ended 2011. Partnership Casualty Losses. As Managing General Partner of numerous partnerships, we have a potential liability for casualty losses in excess of the partnership assets and insurance. We believe the casualty insurance coverage that we and our subcontractors carry is adequate to meet this potential liability. |
BUSINESS SEGMENTS
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BUSINESS SEGMENTS [Abstract] | Â | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting Disclosure [Text Block] | BUSINESS SEGMENTS We separate our operating activities into two segments: natural gas and crude oil sales and natural gas marketing. All material inter-company accounts and transactions between segments have been eliminated. The following tables present our segment information.
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COMMON STOCK [Abstract] | Â | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Text Block] | COMMON STOCK Stock-Based Compensation Plans The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented.
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Stock Appreciation Rights ("SARs") In March 2011, the Compensation Committee of our Board of Directors (the "Compensation Committee") awarded 31,552 SARs to our executive officers. The SARs will vest ratably over a three-year period and may be exercised at any point after vesting through March 2021. Pursuant to the terms of the awards, upon exercise, the executives will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the assumptions presented in the table below. The expected life of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future.
The following table presents the changes in our SARs for the six months ended 2011.
Pursuant to a separation agreement with our former chief executive officer and the original terms of the award, during the three months ended 2011, 29,906 SARs were accelerated to vest, resulting in the acceleration of $0.6 million in stock-based compensation expense. The total compensation cost related to SARs granted and not yet recognized in our statement of operations as of June 30, 2011, was $0.6 million. The cost is expected to be recognized over a weighted average period of 1.8 years. Restricted Stock Awards Time-Based Awards. In March 2011, the Compensation Committee awarded a total of 43,256 time-based restricted shares to our executive officers that vest ratably over a three-year period ending on March 12, 2014. In June 2011, the Compensation Committee awarded 58,122 time-based restricted shares to our new chief executive officer that vest ratably over a three-year period ending on June 10, 2014, and 21,798 time-based restricted shares to our non-employee directors that vest ratably over a three-year period ending on July 1, 2014. Pursuant to a separation agreement with our former chief executive officer and the original terms of the award, during the three months ended 2011, the vesting of 64,442 time-based restricted shares was accelerated, resulting in the acceleration of $1.9 million in stock-based compensation expense. The total compensation cost related to non-vested time-based awards expected to vest and not yet recognized in our statements of operations as of June 30, 2011, was $10.0 million. This cost is expected to be recognized over a weighted average period of 2.1 years. The following table presents the changes in non-vested time-based awards for the six months ended 2011.
Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. Generally, the market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. In March 2011, the Compensation Committee awarded a total of 13,531 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 11 peer companies. The shares are measured over a three-year period ending on December 31, 2013, and can result in a payout between zero and 200% of the total shares awarded. The weighted average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the weighted average assumptions presented in the table below.
Expected volatility was based on a blend of our historical and implied volatility. The expected lives of the awards were based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant or modification and extrapolated to approximate the life of the award. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future. The following table presents the change in non-vested market-based awards for the six months ended 2011.
Pursuant to a separation agreement with our former chief executive officer and the original terms of the award, during the three months ended 2011, the vesting of 4,109 market-based restricted shares was accelerated and 21,927 market-based restricted shares were forfeited. The impact on stock-based compensation for the vesting and forfeiture of these market-based restricted shares was immaterial. The total compensation cost related to non-vested market-based awards expected to vest and not yet recognized in our statement of operations as of June 30, 2011, was $0.4 million. This cost is expected to be recognized over a weighted average period of 2.5 years. Treasury Share Purchases In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to cover tax withholding obligations upon the vesting and exercise of share-based awards. The shares acquired may be retired or reissued to service awards under our 2010 Long-Term Equity Compensation Plan (the "2010 Plan"). For shares that are retired, we first charge any excess of cost over the par value to additional paid-in-capital ("APIC") to the extent we have amounts in APIC, with any remaining excess cost charged to retained earnings. For shares reissued to service awards under the 2010 Plan, shares are recorded at cost and upon reissuance, we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted average cost per share with an offsetting charge to APIC. During the six months ended June 30, 2011, we acquired 38,635 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 35,335 shares were retired. |
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