x | Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 | |
For the quarterly period ended: | June 30, 2013 | |
or | ||
¨ | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 | |
For the transition period from: | ____________ to _____________ |
Delaware (State or other jurisdiction of incorporation or organization) | 64-0844345 (I.R.S. Employer Identification No.) |
200 North Canal Street Natchez, Mississippi (Address of principal executive offices) | 39120 (Zip Code) |
Yes x | No ¨ |
Yes x | No ¨ |
Large accelerated filer ¨ | Accelerated filer x |
Non-accelerated filer ¨ | Smaller reporting company ¨ |
Yes ¨ | No x |
Part I. Financial Information | |
Item 1. Financial Statements (Unaudited) | |
Consolidated Balance Sheets (Unaudited) | |
Consolidated Statements of Operations (Unaudited) | |
Consolidated Statements of Comprehensive Income (Loss) (Unaudited) | |
Consolidated Statements of Cash Flows (Unaudited) | |
Notes to Consolidated Financial Statements (Unaudited) | |
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Item 3. Quantitative and Qualitative Disclosures about Market Risk | |
Item 4. Controls and Procedures | |
Part II. Other Information | |
Item 1. Legal Proceedings | |
Item 1A. Risk Factors | |
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | |
Item 3. Defaults Upon Senior Securities | |
Item 4. Mine Safety Disclosures | |
Item 5. Other Information | |
Item 6. Exhibits | |
June 30, 2013 | December 31, 2012 | ||||||
ASSETS | Unaudited | ||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 13,406 | $ | 1,139 | |||
Accounts receivable | 15,828 | 15,608 | |||||
Fair market value of derivatives | 1,647 | 1,674 | |||||
Other current assets | 904 | 1,502 | |||||
Total current assets | 31,785 | 19,923 | |||||
Oil and natural gas properties, full-cost accounting method: | |||||||
Evaluated properties | 1,583,159 | 1,497,010 | |||||
Less accumulated depreciation, depletion and amortization | (1,317,961 | ) | (1,296,265 | ) | |||
Net oil and natural gas properties | 265,198 | 200,745 | |||||
Unevaluated properties excluded from amortization | 55,182 | 68,776 | |||||
Total oil and natural gas properties | 320,380 | 269,521 | |||||
Other property and equipment, net | 9,926 | 10,058 | |||||
Restricted investments | 3,800 | 3,798 | |||||
Investment in Medusa Spar LLC | 7,946 | 8,568 | |||||
Deferred tax asset | 63,892 | 64,383 | |||||
Other assets, net | 3,474 | 1,922 | |||||
Total assets | $ | 441,203 | $ | 378,173 | |||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable and accrued liabilities | $ | 40,637 | $ | 36,016 | |||
Asset retirement obligations | 6,223 | 2,336 | |||||
Fair market value of derivatives | 106 | 125 | |||||
Total current liabilities | 46,966 | 38,477 | |||||
13% Senior Notes: | |||||||
Principal outstanding | 96,961 | 96,961 | |||||
Deferred credit, net of accumulated amortization of $19,415 and $17,800, respectively | 12,092 | 13,707 | |||||
Total 13% Senior Notes | 109,053 | 110,668 | |||||
Senior secured revolving credit facility | — | 10,000 | |||||
Asset retirement obligations | 7,175 | 10,965 | |||||
Other long-term liabilities | 1,474 | 2,092 | |||||
Total liabilities | 164,668 | 172,202 | |||||
Stockholders' equity: | |||||||
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500 shares authorized: 1,579 and 0 shares outstanding, respectively | 16 | — | |||||
Common stock, $0.01 par value, 60,000 shares authorized; 40,277 and 39,801 shares outstanding, respectively | 404 | 398 | |||||
Capital in excess of par value | 399,380 | 328,116 | |||||
Retained deficit | (123,265 | ) | (122,543 | ) | |||
Total stockholders' equity | 276,535 | 205,971 | |||||
Total liabilities and stockholders' equity | $ | 441,203 | $ | 378,173 |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Operating revenues: | ||||||||||||||||
Crude oil sales | $ | 19,061 | $ | 22,073 | $ | 38,601 | $ | 47,822 | ||||||||
Natural gas sales | 3,699 | 3,287 | 6,700 | 6,833 | ||||||||||||
Total operating revenues | 22,760 | 25,360 | 45,301 | 54,655 | ||||||||||||
Operating expenses: | ||||||||||||||||
Lease operating expenses | 5,384 | 5,246 | 11,142 | 13,484 | ||||||||||||
Production taxes | 687 | 575 | 1,226 | 1,122 | ||||||||||||
Depreciation, depletion and amortization | 10,654 | 11,844 | 21,696 | 24,033 | ||||||||||||
General and administrative | 4,545 | 4,374 | 8,284 | 9,405 | ||||||||||||
Accretion expense | 533 | 562 | 1,098 | 1,135 | ||||||||||||
Total operating expenses | 21,803 | 22,601 | 43,446 | 49,179 | ||||||||||||
Income from operations | 957 | 2,759 | 1,855 | 5,476 | ||||||||||||
Other (income) expenses: | ||||||||||||||||
Interest expense | 1,537 | 2,384 | 3,052 | 4,961 | ||||||||||||
Gain on early extinguishment of debt | — | (1,366 | ) | — | (1,366 | ) | ||||||||||
Gain on derivative contracts | (1,981 | ) | (3,505 | ) | (1,563 | ) | (3,575 | ) | ||||||||
Other income, net | (44 | ) | (157 | ) | (89 | ) | (461 | ) | ||||||||
Total other (income) expenses, net | (488 | ) | (2,644 | ) | 1,400 | (441 | ) | |||||||||
Income before income taxes | 1,445 | 5,403 | 455 | 5,917 | ||||||||||||
Income tax expense | 663 | 1,610 | 494 | 1,754 | ||||||||||||
Income (loss) before equity in earnings of Medusa Spar LLC | 782 | 3,793 | (39 | ) | 4,163 | |||||||||||
Equity in (loss) earnings of Medusa Spar LLC | (24 | ) | 6 | (3 | ) | 124 | ||||||||||
Net income (loss) | 758 | 3,799 | (42 | ) | 4,287 | |||||||||||
Preferred stock dividends | (680 | ) | — | (680 | ) | — | ||||||||||
Net income (loss) available to common shareholders | $ | 78 | $ | 3,799 | $ | (722 | ) | $ | 4,287 | |||||||
Net income (loss) per common share: | ||||||||||||||||
Basic | $ | 0.00 | $ | 0.10 | $ | (0.02 | ) | $ | 0.11 | |||||||
Diluted | $ | 0.00 | $ | 0.09 | $ | (0.02 | ) | $ | 0.11 | |||||||
Shares used in computing net income (loss) per common share: | ||||||||||||||||
Basic | 40,089 | 39,399 | 39,941 | 39,375 | ||||||||||||
Diluted | 40,323 | 40,155 | 39,941 | 40,204 |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Net income (loss) | $ | 758 | $ | 3,799 | $ | (42 | ) | $ | 4,287 | |||||||
Other comprehensive (loss) income: | ||||||||||||||||
Change in fair value of derivatives designated as hedges, | — | 1,393 | — | (77 | ) | |||||||||||
net of tax (See Note 5) | ||||||||||||||||
Comprehensive income (loss) | 758 | 5,192 | (42 | ) | 4,210 | |||||||||||
Preferred stock dividends | (680 | ) | — | (680 | ) | — | ||||||||||
Comprehensive income (loss) available to common shareholders | $ | 78 | $ | 5,192 | $ | (722 | ) | $ | 4,210 |
Six Months Ended June 30, | ||||||||
2013 | 2012 | |||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | $ | (42 | ) | $ | 4,287 | |||
Adjustments to reconcile net income to cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 22,405 | 24,676 | ||||||
Accretion expense | 1,098 | 1,135 | ||||||
Amortization of non-cash debt related items | 228 | 225 | ||||||
Amortization of deferred credit | (1,615 | ) | (1,538 | ) | ||||
Non-cash gain on early extinguishment of debt | — | (1,366 | ) | |||||
Equity in loss (earnings) of Medusa Spar LLC | 3 | (124 | ) | |||||
Deferred income tax expense | 494 | 1,754 | ||||||
Unrealized loss (gain) on derivative contracts | (249 | ) | (3,897 | ) | ||||
Non-cash expense related to equity share-based awards | 734 | 722 | ||||||
Change in the fair value of liability share-based awards | (852 | ) | 989 | |||||
Payments to settle asset retirement obligations | (615 | ) | (1,029 | ) | ||||
Changes in current assets and liabilities: | ||||||||
Accounts receivable | 789 | (2,036 | ) | |||||
Other current assets | 598 | 63 | ||||||
Current liabilities | (324 | ) | 4,756 | |||||
Payments to settle vested liability share-based awards | (239 | ) | (199 | ) | ||||
Change in natural gas balancing receivable | (118 | ) | (95 | ) | ||||
Change in natural gas balancing payable | (62 | ) | (17 | ) | ||||
Change in other long-term liabilities | (206 | ) | — | |||||
Change in other assets, net | (1,790 | ) | (865 | ) | ||||
Cash provided by operating activities | $ | 20,237 | $ | 27,441 | ||||
Cash flows from investing activities: | ||||||||
Capital expenditures | (58,385 | ) | (72,538 | ) | ||||
Acquisition | (11,000 | ) | — | |||||
Proceeds from sale of mineral interest and equipment | 1,389 | 522 | ||||||
Distribution from Medusa Spar LLC | 616 | 1,120 | ||||||
Cash used in investing activities | $ | (67,380 | ) | $ | (70,896 | ) | ||
Cash flows from financing activities: | ||||||||
Borrowings on senior secured revolving credit facility | 31,000 | 10,000 | ||||||
Payments on senior secured revolving credit facility | (41,000 | ) | — | |||||
Redemption of 13% senior notes | — | (10,225 | ) | |||||
Issuance of preferred stock | 70,090 | — | ||||||
Payment of preferred stock dividends | (680 | ) | — | |||||
Taxes paid related to exercise of employee stock options | — | (2 | ) | |||||
Cash provided by (used in) financing activities | $ | 59,410 | $ | (227 | ) | |||
Net change in cash and cash equivalents | 12,267 | (43,682 | ) | |||||
Beginning of period cash and cash equivalents | 1,139 | 43,795 | ||||||
End of period cash and cash equivalents | $ | 13,406 | $ | 113 |
Footnotes to the Financial Statements Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
(a) Net income (loss) available to common shareholders | $ | 78 | $ | 3,799 | $ | (722 | ) | $ | 4,287 | |||||||
(b) Weighted average shares outstanding | 40,089 | 39,399 | 39,941 | 39,375 | ||||||||||||
Dilutive impact of stock options | — | 7 | — | 14 | ||||||||||||
Dilutive impact of restricted stock | 234 | 749 | — | 815 | ||||||||||||
(c) Weighted average shares outstanding for diluted net income (loss) per share | 40,323 | 40,155 | 39,941 | 40,204 | ||||||||||||
Basic net income (loss) per share (a/b) | $ | 0.00 | $ | 0.10 | $ | (0.02 | ) | $ | 0.11 | |||||||
Diluted net income (loss) per share (a/c) | $ | 0.00 | $ | 0.09 | $ | (0.02 | ) | $ | 0.11 | |||||||
The following were excluded from the diluted EPS calculation because their effect would be anti-dilutive: | ||||||||||||||||
Stock options | 52 | 67 | 52 | 52 | ||||||||||||
Restricted stock | 267 | 1,013 | 267 | 1,013 |
June 30, 2013 | December 31, 2012 | |||||||
Principal components: | ||||||||
Credit Facility | $ | — | $ | 10,000 | ||||
13% Senior Notes due 2016, principal | 96,961 | 96,961 | ||||||
Total principal outstanding | 96,961 | 106,961 | ||||||
Non-cash components: | ||||||||
13% Senior Notes due 2016 unamortized deferred credit | 12,092 | 13,707 | ||||||
Total carrying value of borrowings | $ | 109,053 | $ | 120,668 |
Footnotes to the Financial Statements Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data. |
Gross Carrying | Accumulated Amortization at | Carrying Value at | Amortization Recorded during Current Year as a Reduction of | Estimated Amortization to be Recorded during the Remainder of the | ||||
Amount | 6/30/2013 | 6/30/2013 | Interest Expense | Current Year | ||||
$31,507 | $19,415 | $12,092 | $1,615 | $1,684 |
Footnotes to the Financial Statements Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data. |
Commodity | Instrument | Average Notional Volumes per Month | Quantity Type | Put/Call Price | Fixed-Price Swap | Period | Designation under ASC 815 | |||||||||||
Natural gas | Swap | 91 | MMbtu | n/a | $ | 3.52 | Jul13 - Dec13 | Not Designated | ||||||||||
Natural gas | Put Option | 91 | MMbtu | $ | 3.00 | n/a | Jul13 - Dec13 | Not Designated | ||||||||||
Crude oil | Swap | 40 | Bbls | n/a | $ | 101.30 | Jul13 - Dec13 | Not Designated | ||||||||||
Natural gas | Call Option | 38 | MMbtu | $ | 4.75 | n/a | Jan14 - Dec14 | Not Designated | ||||||||||
Crude oil | Swap | 30 | Bbls | n/a | $ | 93.35 | Jan14 - Dec14 | Not Designated | ||||||||||
Crude oil | Put Option | 30 | Bbls | $ | 70.00 | n/a | Jan14 - Dec14 | Not Designated |
Balance Sheet Presentation | Asset Fair Value | Liability Fair Value | Net Derivative Fair Value | |||||||||||||||||||||||||
Commodity | Classification | Line Description | 06/30/13 | 12/31/12 | 06/30/13 | 12/31/12 | 06/30/13 | 12/31/12 | ||||||||||||||||||||
Natural gas | Current | Fair market value of derivatives | $ | — | $ | — | $ | (106 | ) | $ | (125 | ) | $ | (106 | ) | $ | (125 | ) | ||||||||||
Natural gas | Non-current | Other long-term liabilities | — | — | (38 | ) | (116 | ) | (38 | ) | (116 | ) | ||||||||||||||||
Crude oil | Current | Fair market value of derivatives | 1,647 | 1,674 | — | — | 1,647 | 1,674 | ||||||||||||||||||||
Crude oil | Non-current | Other long-term assets | 428 | 250 | — | — | 428 | 250 | ||||||||||||||||||||
Totals | $ | 2,075 | $ | 1,924 | $ | (144 | ) | $ | (241 | ) | $ | 1,931 | $ | 1,683 |
Presented without | As Presented with | |||||||||||
Effects of Netting | Effects of Netting | Effects of Netting | ||||||||||
Current assets: Fair value of hedging contracts | $ | 2,330 | $ | (683 | ) | $ | 1,647 | |||||
Long-term assets: Fair value of hedging contracts | 852 | (424 | ) | 428 | ||||||||
Current liabilities: Fair value of hedging contracts | (789 | ) | 683 | (106 | ) | |||||||
Long-term liabilities: Fair value of hedging contracts | (462 | ) | 424 | (38 | ) |
Footnotes to the Financial Statements Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Natural gas derivatives | ||||||||||||||||
Realized gain (loss), net | $ | (156 | ) | $ | — | $ | (107 | ) | $ | — | ||||||
Unrealized gain (loss), net | 485 | (331 | ) | 97 | (331 | ) | ||||||||||
Sub-total gain (loss), net | $ | 329 | $ | (331 | ) | $ | (10 | ) | $ | (331 | ) | |||||
Crude oil derivatives | ||||||||||||||||
Realized gain, net | $ | 849 | $ | — | $ | 1,422 | $ | — | ||||||||
Unrealized gain, net | 803 | 3,836 | 151 | 3,906 | ||||||||||||
Sub-total gain, net | $ | 1,652 | $ | 3,836 | $ | 1,573 | $ | 3,906 | ||||||||
Total gain on derivative instruments, net | $ | 1,981 | $ | 3,505 | $ | 1,563 | $ | 3,575 |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Amount of gain reclassified from OCI into income (effective portion) | $ | — | $ | 512 | $ | — | $ | 512 | ||||||||
Amount of gain recognized in income (ineffective portion and amount excluded from effectiveness testing) | — | 92 | — | 322 |
Commodity | Instrument | Average Notional Volumes per Month | Quantity Type | Put/Call Price | Fixed-Price Swap | Period | Designation under ASC 815 | |||||||||
Crude oil | Swap | 18 | Bbls | n/a | $ | 102.08 | Sep13 - Dec13 | Not Designated | ||||||||
Crude oil | Swap | 9 | Bbls | n/a | $ | 94.58 | Jan14 - Dec14 | Not Designated |
Footnotes to the Financial Statements Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data. |
June 30, 2013 | December 31, 2012 | |||||||||||||||
Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||||
Credit Facility | $ | — | $ | — | $ | 10,000 | $ | 10,000 | ||||||||
13% Senior Notes due 2016 (1) | 109,053 | 101,615 | 110,668 | 100,112 | ||||||||||||
Total | $ | 109,053 | $ | 101,615 | $ | 120,668 | $ | 110,112 |
Footnotes to the Financial Statements Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data. |
As of June 30, 2013 | Balance Sheet Presentation | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Assets | ||||||||||||||||||
Derivative financial instruments - current | Fair market value of derivatives | $ | — | $ | 1,647 | $ | — | $ | 1,647 | |||||||||
Derivative financial instruments - non-current | Other long-term assets | — | 428 | — | 428 | |||||||||||||
Sub-total assets | — | 2,075 | — | 2,075 | ||||||||||||||
Liabilities | ||||||||||||||||||
Derivative financial instruments - current | Fair market value of derivatives | $ | — | $ | 106 | $ | — | $ | 106 | |||||||||
Derivative financial instruments - non-current | Other long-term liabilities | — | 38 | — | 38 | |||||||||||||
Sub-total liabilities | Other long-term liabilities | — | 144 | — | 144 | |||||||||||||
Total | $ | — | $ | 1,931 | $ | — | $ | 1,931 | ||||||||||
As of 12/31/2012 | Balance Sheet Presentation | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Assets | ||||||||||||||||||
Derivative financial instruments - current | Fair market value of derivatives | $ | — | $ | 1,674 | $ | — | $ | 1,674 | |||||||||
Derivative financial instruments - non-current | Other long-term assets | — | 250 | — | 250 | |||||||||||||
Sub-total assets | — | 1,924 | — | 1,924 | ||||||||||||||
Liabilities | ||||||||||||||||||
Derivative financial instruments - current | Fair market value of derivatives | $ | — | $ | 125 | $ | — | $ | 125 | |||||||||
Derivative financial instruments - non-current | Other long-term liabilities | — | 116 | — | 116 | |||||||||||||
Sub-total liabilities | — | 241 | — | 241 | ||||||||||||||
Total | $ | — | $ | 1,683 | $ | — | $ | 1,683 |
Footnotes to the Financial Statements Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data. |
Asset retirement obligations at January 1, 2013 | $ | 13,301 | ||
Accretion expense | 1,098 | |||
Liabilities incurred | 572 | |||
Liabilities settled | (397 | ) | ||
Revisions to estimate | (1,176 | ) | ||
Asset retirement obligations at end of period | 13,398 | |||
Less: Current asset retirement obligations | 6,223 | |||
Long-term asset retirement obligations at June 30, 2013 | $ | 7,175 |
• | the timing and extent of changes in market conditions and prices for commodities (including regional basis differentials), |
• | our ability to transport our production to the most favorable markets or at all, |
• | the timing and extent of our success in discovering, developing, producing and estimating reserves, |
• | our ability to respond to low natural gas prices, |
• | our ability to fund our planned capital investments, |
• | the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives, |
• | the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services, |
• | our future property acquisition or divestiture activities, including the possible sale of our Medusa property, |
• | the effects of weather, |
• | increased competition, |
• | the financial impact of accounting regulations and critical accounting policies, |
• | the comparative cost of alternative fuels, |
• | conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed, |
• | credit risk relating to the risk of loss as a result of non-performance by our counterparties, and |
• | any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”). |
• | In May, we successfully completed a $75 million Preferred Stock offering, which provided us with $70 million of net proceeds to accelerate the development of our Permian acreage and to retire the balance on our Credit Facility, leaving $75 million of available borrowing capacity on the Credit Facility. |
• | In June, we expanded our acreage position in the Permian Basin with the acquisition of 2,468 gross (2,186 net) acres in the southern portion of the Midland Basin for approximately $11 million. The properties acquired were producing approximately 145 net Boe per day at the time of acquisition. |
• | During August, we increased our capital budget by 36% to $170 million with approximately 90% of our budgeted operating expenditures (including drilling, completion, and infrastructure) allocated to our Midland Basin operations in an effort to accelerate the development of our fields in the southern and central portions of the Basin. As a result of this budget increase, we expect to increase the total number of Permian wells planned to be drilled in 2013 to 31 gross wells, including 22 horizontal wells (completion of 17 gross wells) and nine vertical wells (completion of eight gross wells) . |
• | On August 1, 2013, we accepted delivery of an additional horizontal drilling rig under a one-year contract to support our expanded drilling program. |
• | To date in 2013, we continue to execute our horizontal drilling program (gross production data provided): |
◦ | Two recent Wolfcamp B shale wells in the East Bloxom field produced at a peak (24-hour) rate of 1,258 Boe per day and an average peak 30-day rate of 634 Boe per day. Since commencing program development of this field in 2012, we have drilled seven wells with an average lateral length of 7,000 feet and completed four wells with demonstrated average peak initial (24-hour) rates of 1,031 Boe per day. |
◦ | At our Taylor Draw field, we placed one well targeting the lower Wolfcamp B shale on production. The well produced at a 24-hour rate of 860 Boe per day. We also completed three additional wells in the upper Wolfcamp B zone that are in the process of flowing back. The average lateral length for these four drill wells and an additional well completed in the first quarter of 2013 is 4,700 feet. |
• | Also during 2013, we continue to execute our vertical Wolfberry drilling program with positive initial results. In our Pecan Acres field, our first well to simultaneous complete multiple zones down to the Woodford shale produced at a gross peak initial (24-hour) production rate of 543 Boe per day. |
Net Production (MBoe) | ||||||||||||
Three Months Ended June 30, | ||||||||||||
2013 | 2012 | Change | % Change | |||||||||
Onshore - Permian Basin: | ||||||||||||
Southern Portion | 122 | 85 | 37 | 44 | % | |||||||
Central Portion | 48 | 57 | (9 | ) | (16 | )% | ||||||
Total Permian | 170 | 142 | 28 | 20 | % | |||||||
Offshore - Deepwater Properties | ||||||||||||
Medusa | 73 | 90 | (17 | ) | (19 | )% | ||||||
Habanero | — | 40 | (40 | ) | (100 | )% | ||||||
Total Deepwater | 73 | 130 | (57 | ) | (44 | )% | ||||||
Other: | ||||||||||||
Haynesville Shale | 7 | 17 | (10 | ) | (59 | )% | ||||||
Gulf of Mexico shelf | 79 | 85 | (6 | ) | (7 | )% | ||||||
Total Other | 86 | 102 | (16 | ) | (16 | )% | ||||||
Total | 329 | 374 | (45 | ) | (12 | )% |
Net Production (MBoe) | ||||||||||||
Six Months Ended June 30, | ||||||||||||
2013 | 2012 | Change | % Change | |||||||||
Onshore - Permian Basin: | ||||||||||||
Southern Portion | 216 | 162 | 54 | 33 | % | |||||||
Central Portion | 98 | 94 | 4 | 4 | % | |||||||
Total Permian | 314 | 256 | 58 | 23 | % | |||||||
Offshore - Deepwater Properties | ||||||||||||
Medusa | 178 | 225 | (47 | ) | (21 | )% | ||||||
Habanero | — | 81 | (81 | ) | (100 | )% | ||||||
Total Deepwater | 178 | 306 | (128 | ) | (42 | )% | ||||||
Other: | ||||||||||||
Haynesville Shale | 14 | 23 | (9 | ) | (39 | )% | ||||||
Gulf of Mexico shelf | 152 | 181 | (29 | ) | (16 | )% | ||||||
Total Other | 166 | 204 | (38 | ) | (19 | )% | ||||||
Total | 658 | 766 | (108 | ) | (14 | )% |
Crude Oil Wells | Natural Gas Wells | |||||||||||
Gross | Net | Gross | Net | |||||||||
Working interest | 118 | 95.23 | 11 | 4.8 | ||||||||
Royalty interest | 3 | 0.10 | 2 | 0.08 | ||||||||
Total | 121 | 95.33 | 13 | 4.88 |
Drilled | Completed (a) | |||||||||||
Gross | Net | Gross | Net | |||||||||
Southern portion: | ||||||||||||
Horizontal wells | 9 | 8.22 | 5 | 4.51 | ||||||||
Central portion: | ||||||||||||
Vertical wells | 3 | 1.75 | 4 | 2.29 | ||||||||
Horizontal wells | — | — | — | — | ||||||||
Total central portion | 3 | 1.75 | 4 | 2.29 | ||||||||
Northern portion: | ||||||||||||
Vertical wells | — | — | 1 | 0.75 | ||||||||
Horizontal wells | — | — | 1 | 0.75 | ||||||||
Total northern portion | — | — | 2 | 1.50 | ||||||||
Total | 12 | 9.97 | 11 | 8.30 |
(a) | Completions include wells drilled prior to the first half of 2013. |
Midland Basin | $ | 142 | ||
Gulf of Mexico | 11 | |||
Total budgeted capital expenditures | $ | 153 | ||
Capitalized general and administrative costs | 13 | |||
Capitalized interest and other | 4 | |||
Total budgeted capitalized expenses | $ | 17 | ||
Total operational budget | 170 | |||
Acquisition - Southern Midland Basin | 11 | |||
Total capital expenditures | $ | 181 |
Southern Midland Basin | $ | 43 | ||
Central Midland Basin | 4 | |||
Northern Midland Basin | 3 | |||
Total capital expenditures | $ | 50 | ||
Capitalized general and administrative costs | 5 | |||
Capitalized interest and other | 2 | |||
Total capitalized expenses | $ | 7 | ||
Total operational expenditures | 57 | |||
Acquisition - Southern Midland Basin | 11 | |||
Total capital expenditures | $ | 68 |
Three Months Ended June 30, | ||||||||||||||||
2013 | 2012 | Change | % Change | |||||||||||||
Net production: | ||||||||||||||||
Crude oil (MBbls) | 198 | 223 | (25 | ) | (11 | )% | * | |||||||||
Natural gas (MMcf) | 787 | 902 | (115 | ) | (13 | )% | * | |||||||||
Total production (MBoe) | 329 | 374 | (45 | ) | (12 | )% | ||||||||||
Average daily production (MBoe) | 3.6 | 4.1 | (0.5 | ) | (12 | )% | ||||||||||
Average realized sales price (a): | ||||||||||||||||
Crude oil (Bbl) | $ | 96.27 | $ | 98.78 | $ | (2.51 | ) | (3 | )% | |||||||
Natural gas (Mcf) | $ | 4.70 | $ | 3.65 | $ | 1.05 | 29 | % | ||||||||
Average realized sales price on an equivalent basis (Boe) | $ | 69.18 | $ | 67.85 | $ | 1.33 | 2 | % | ||||||||
Crude oil and natural gas revenues (in thousands): | ||||||||||||||||
Crude oil revenue | $ | 19,061 | $ | 22,073 | $ | (3,012 | ) | (14 | )% | |||||||
Natural gas revenue | 3,699 | 3,287 | 411 | 13 | % | |||||||||||
Total | $ | 22,760 | $ | 25,360 | $ | (2,600 | ) | (10 | )% | |||||||
Additional per Boe data: | ||||||||||||||||
Average realized sales price | $ | 69.18 | $ | 67.85 | $ | 1.33 | 2 | % | ||||||||
Lease operating expense | 16.36 | 14.03 | 2.33 | 17 | % | |||||||||||
Production taxes | 2.09 | 1.54 | 0.55 | 36 | % | |||||||||||
Operating margin | $ | 50.73 | $ | 52.28 | $ | (1.55 | ) | (3 | )% | |||||||
Other expenses per Boe: | ||||||||||||||||
Depletion, depreciation and amortization | $ | 32.38 | $ | 31.69 | $ | 0.69 | 2 | % | ||||||||
General and administrative | 13.81 | 11.70 | 2.11 | 18 | % | |||||||||||
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price: | ||||||||||||||||
Average NYMEX price per barrel ("Bbl") of crude oil | $ | 94.22 | $ | 93.49 | $ | 0.73 | 1 | % | ||||||||
Basis differential and quality adjustments | 2.52 | 3.68 | (1.16 | ) | (32 | )% | ||||||||||
Transportation | (0.47 | ) | (0.68 | ) | 0.21 | (31 | )% | |||||||||
Hedging | — | 2.29 | (2.29 | ) | (100 | )% | ||||||||||
Average realized price per Bbl of crude oil | $ | 96.27 | $ | 98.78 | (2.51 | ) | (3 | )% | ||||||||
Average NYMEX price per million British thermal units (“MMBtu”) | $ | 4.01 | $ | 2.35 | $ | 1.66 | 71 | % | ||||||||
Basis differential, quality and Btu adjustments | 0.69 | 1.30 | (0.61 | ) | (47 | )% | ||||||||||
Average realized price per Mcf of natural gas | $ | 4.70 | $ | 3.65 | $ | 1.05 | 29 | % |
Six Months Ended June 30, | ||||||||||||||||
2013 | 2012 | Change | % Change | |||||||||||||
Net production: | ||||||||||||||||
Crude oil (MBbls) | 404 | 465 | (61 | ) | (13 | )% | * | |||||||||
Natural gas (MMcf) | 1,525 | 1,806 | (281 | ) | (16 | )% | * | |||||||||
Total production (MBoe) | 658 | 766 | (108 | ) | (14 | )% | ||||||||||
Average daily production (MBoe) | 3.6 | 4.2 | (0.6 | ) | (14 | )% | ||||||||||
Average realized sales price (a): | ||||||||||||||||
Crude oil (Bbl) | $ | 95.55 | $ | 102.86 | $ | (7.31 | ) | (7 | )% | |||||||
Natural gas (Mcf) | $ | 4.39 | $ | 3.78 | $ | 0.61 | 16 | % | ||||||||
Average realized sales price on an equivalent basis (Boe) | $ | 68.85 | $ | 71.36 | $ | (2.51 | ) | (4 | )% | |||||||
Crude oil and natural gas revenues (in thousands): | ||||||||||||||||
Crude oil revenue | $ | 38,601 | $ | 47,822 | $ | (9,221 | ) | (19 | )% | |||||||
Natural gas revenue | 6,700 | 6,833 | (133 | ) | (2 | )% | ||||||||||
Total | $ | 45,301 | $ | 54,655 | $ | (9,354 | ) | (17 | )% | |||||||
Additional per Boe data: | ||||||||||||||||
Average realized sales price | $ | 68.85 | $ | 71.36 | $ | (2.51 | ) | (4 | )% | |||||||
Lease operating expense | 16.93 | 19.07 | (2.14 | ) | (11 | )% | ||||||||||
Production taxes | 1.86 | 1.46 | 0.40 | 27 | % | |||||||||||
Operating margin | $ | 50.06 | $ | 50.83 | $ | (0.77 | ) | (2 | )% | |||||||
Other expenses per Boe: | ||||||||||||||||
Depletion, depreciation and amortization | $ | 32.97 | $ | 31.38 | $ | 1.59 | 5 | % | ||||||||
General and administrative | 12.59 | 12.28 | 0.31 | 3 | % | |||||||||||
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price: | ||||||||||||||||
Average NYMEX price per barrel ("Bbl") of crude oil | $ | 94.30 | $ | 98.21 | $ | (3.91 | ) | (4 | )% | |||||||
Basis differential and quality adjustments | 1.81 | 4.33 | (2.52 | ) | (58 | )% | ||||||||||
Transportation | (0.56 | ) | (0.78 | ) | 0.22 | (28 | )% | |||||||||
Hedging | — | 1.10 | (1.10 | ) | (100 | )% | ||||||||||
Average realized price per Bbl of crude oil | $ | 95.55 | $ | 102.86 | $ | (7.31 | ) | (7 | )% | |||||||
Average NYMEX price per million British thermal units (“MMBtu”) | $ | 3.75 | $ | 2.43 | $ | 1.32 | 54 | % | ||||||||
Basis differential, quality and Btu adjustments | 0.64 | 1.35 | (0.71 | ) | (53 | )% | ||||||||||
Average realized price per Mcf of natural gas | $ | 4.39 | $ | 3.78 | $ | 0.61 | 16 | % |
(in thousands) | Crude Oil | Natural Gas | Total | |||||||||
Revenues for the three-months ended June 30, 2011 | $ | 29,087 | $ | 7,747 | $ | 36,834 | ||||||
Volume increase (decrease) | $ | (5,455 | ) | $ | (2,713 | ) | $ | (8,168 | ) | |||
Price increase (decrease) | (2,071 | ) | (1,747 | ) | (3,818 | ) | ||||||
Impact of hedges | 512 | — | 512 | |||||||||
Net increase (decrease) in 2012 | (7,014 | ) | (4,460 | ) | (11,474 | ) | ||||||
Revenues for the three-months ended June 30, 2012 | $ | 22,073 | $ | 3,287 | $ | 25,360 | ||||||
Volume increase (decrease) | $ | (2,475 | ) | $ | (419 | ) | $ | (2,894 | ) | |||
Price increase (decrease) | (1,386 | ) | 987 | (399 | ) | |||||||
Impact of hedges | 849 | (156 | ) | 693 | ||||||||
Net increase (decrease) in 2013 | (3,012 | ) | 412 | (2,600 | ) | |||||||
Revenues for the three-months ended June 30, 2013 | $ | 19,061 | $ | 3,699 | $ | 22,760 |
(in thousands) | Crude Oil | Natural Gas | Total | |||||||||
Revenues for the six-months ended June 30, 2011 | $ | 47,891 | $ | 14,392 | $ | 62,283 | ||||||
Volume increase (decrease) | $ | (1,070 | ) | $ | (4,872 | ) | $ | (5,942 | ) | |||
Price increase (decrease) | 489 | (2,687 | ) | (2,198 | ) | |||||||
Impact of hedges | 512 | — | 512 | |||||||||
Net increase (decrease) in 2012 | (69 | ) | (7,559 | ) | (7,628 | ) | ||||||
Revenues for the six-months ended June 30, 2012 | $ | 47,822 | $ | 6,833 | $ | 54,655 | ||||||
Volume increase (decrease) | $ | (6,273 | ) | $ | (1,063 | ) | $ | (7,336 | ) | |||
Price increase (decrease) | (4,370 | ) | 1,038 | (3,332 | ) | |||||||
Impact of hedges | 1,422 | (108 | ) | 1,314 | ||||||||
Net increase (decrease) in 2013 | (9,221 | ) | (133 | ) | (9,354 | ) | ||||||
Revenues for the six-months ended June 30, 2013 | $ | 38,601 | $ | 6,700 | $ | 45,301 |
(in thousands except per unit data) | Three Months Ended June 30, | |||||||||||||||||||||||||||||
Per | Per | Total Change | Boe Change | |||||||||||||||||||||||||||
2013 | Boe | 2012 | Boe | $ | % | $ | % | |||||||||||||||||||||||
Lease operating expenses | $ | 5,384 | $ | 16.36 | $ | 5,246 | $ | 14.03 | $ | 138 | 3 | % | $ | 2.33 | 17 | % | ||||||||||||||
Production taxes | 687 | 2.09 | 575 | 1.54 | 112 | 19 | % | 0.55 | 36 | % | ||||||||||||||||||||
Depreciation, depletion and amortization | 10,654 | 32.38 | 11,844 | 31.69 | (1,190 | ) | (10 | )% | 0.69 | 2 | % | |||||||||||||||||||
General and administrative | 4,545 | 13.81 | 4,374 | 11.70 | 171 | 4 | % | nm | nm | |||||||||||||||||||||
Accretion expense | 533 | 1.62 | 562 | 1.50 | (29 | ) | (5 | )% | nm | nm |
(in thousands except per unit data) | Six Months Ended June 30, | |||||||||||||||||||||||||||||
Per | Per | Total Change | Boe Change | |||||||||||||||||||||||||||
2013 | Boe | 2012 | Boe | $ | % | $ | % | |||||||||||||||||||||||
Lease operating expenses | $ | 11,142 | $ | 16.93 | $ | 13,484 | $ | 17.60 | $ | (2,342 | ) | (17 | )% | $ | (0.67 | ) | (4 | )% | ||||||||||||
Production taxes | 1,226 | 1.86 | 1,122 | 1.47 | 104 | 9 | % | 0.39 | 27 | % | ||||||||||||||||||||
Depreciation, depletion and amortization | 21,696 | 32.97 | 24,033 | 31.38 | (2,337 | ) | (10 | )% | 1.59 | 5 | % | |||||||||||||||||||
General and administrative | 8,284 | 12.59 | 9,405 | 12.28 | (1,121 | ) | (12 | )% | nm | nm | ||||||||||||||||||||
Accretion expense | 1,098 | 1.67 | 1,135 | 1.48 | (37 | ) | (3 | )% | nm | nm |
(in thousands) | Three Months Ended June 30, | ||||||||||||||
2013 | 2012 | $ Change | % Change | ||||||||||||
Interest expense | $ | 1,537 | $ | 2,384 | $ | (847 | ) | (36 | )% | ||||||
Gain on early extinguishment of debt | — | (1,366 | ) | 1,366 | 100 | % | |||||||||
Gain on derivative contracts | (1,981 | ) | (3,505 | ) | 1,524 | 43 | % | ||||||||
Other income, net | (44 | ) | (157 | ) | 113 | (72 | )% | ||||||||
Income tax expense | 663 | 1,610 | (947 | ) | (59 | )% | |||||||||
Equity in earnings of Medusa Spar LLC | (24 | ) | 6 | (30 | ) | (500 | )% | ||||||||
Preferred stock dividends | 680 | — | 680 | 100 | % |
(in thousands) | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | $ Change | % Change | ||||||||||||
Interest expense | $ | 3,052 | $ | 4,961 | $ | (1,909 | ) | (38 | )% | ||||||
Gain on early extinguishment of debt | — | (1,366 | ) | 1,366 | (100 | )% | |||||||||
Gain on derivative contracts | (1,563 | ) | (3,575 | ) | 2,012 | (56 | )% | ||||||||
Other income, net | (89 | ) | (461 | ) | 372 | (81 | )% | ||||||||
Income tax expense | 494 | 1,754 | (1,260 | ) | (72 | )% | |||||||||
Equity in earnings of Medusa Spar LLC | (3 | ) | 124 | (127 | ) | (102 | )% | ||||||||
Preferred stock dividends | 680 | — | 680 | 100 | % |
Exhibit | ||
Number | Description |
3.1 | Certificate of Incorporation of the Company, as amended (incorporated by reference from Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed March 15, 2004, File No. 001-14039) |
3.2 | Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) |
3.3 | Certificate of Amendment to Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039) |
3.4 | Certificate of Amendment to the Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.4 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-14039) |
3.5 | Certificate of Designation of Rights and Preferences of 10.0% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A filed on May 23, 2013) |
4.1 | Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) |
4.2 | Indenture for the Company’s 13.00% Senior Notes due 2016, dated November 24, 2009, between Callon Petroleum Company, the subsidiary guarantors described therein, Regions Bank and American Stock Transfer & Trust Company (incorporated by reference to Exhibit T3C to the Company’s Form T3, filed November 19, 2009, File No. 022-28916) |
4.3 | Form of Certificate representing the 10.0% Series A Cumulative Preferred Stock (incorporated herein by reference to Exhibit 4.1 of the Company’s Form 8-A filed on May 23, 2013) |
10.1 | Amendment No. 2 to the Fourth Amended and Restated Credit Agreement dated as of May 10, 2013 between Callon Petroleum Company, Callon Petroleum Operating Company, the “Lenders” described therein, and Regions Bank, as Administrative Agent (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed May 21, 2013). |
10.2 | Underwriting Agreement dated as of May 22, 2013 between Callon Petroleum Company and Janney Montgomery Scott LLC, Sterne, Agee & Leach, Inc. and MLV & Co. LLC as representative of the several underwriters named therein (incorporated by reference to Exhibit 1.1 of the Company’s Report on Form 8-K filed May 28, 2013). |
31.1 | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.2 | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32 | Section 1350 Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
* | Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability. |
Callon Petroleum Company | ||
Signature | Title | Date |
/s/ Fred L. Callon | President and Chief Executive Officer | August 8, 2013 |
Fred L. Callon | ||
/s/ B.F. Weatherly | Executive Vice President and | August 8, 2013 |
B.F. Weatherly | Chief Financial Officer |
Date: | August 8, 2013 | /s/ Fred L. Callon | |
Fred L. Callon, President and Chief Executive Officer | |||
(Principal executive officer) |
1. | I have reviewed this Quarterly Report on Form 10-Q of Callon Petroleum Company; |
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 officers 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: |
5. | The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function): |
Date: | August 8, 2013 | /s/ B. F. Weatherly | |
B. F. Weatherly, Executive Vice President and | |||
Chief Financial Officer (Principal Financial Officer) |
Date: | August 8, 2013 | /s/ Fred L. Callon | |
Fred L. Callon (principal executive officer, director) | |||
Date: | August 8, 2013 | /s/ B. F. Weatherly | |
B. F. Weatherly (principal financial officer, director) |
M,6#4M&OHT"K)`\!`&`-A!`_\`'C7;_P#"YO!O_/Y<_P#@,U<)\5/''AKQ M;X?M8=,N)GO(+D.`\+*-A4@\GWQ^532]I[1.2'+EY;(\CJY::3J6H1M)9:?= MW,:G:6AA9P#Z9`ZU3KZ"^`W/A#4/^O\`;_T6E=M:I[./,C"$>9V/%H/"7B.Y M<+%H.IL3Q_QZN!^>*ZC2/@WXLU)E:Y@AT^$]6N)`6Q[*N3GZXKZ6HKBEBYO9 M&ZHKJ>?>%?A%H/AYTNKH'4KU>0\ZC8I]53^IS7H(XHHKFE.4G>3-$DM@HHHJ M1A3)H8KB%X9HUDBD4JZ.,A@>H([BGT4`?/'Q%^%5SH,LVJZ)$\^EDEGA7E[? M_%??MW]:\OK[7(!&",BO,_&/P"/$/AEV_M'3I1"O_+Q&-\1_X$.GXX-<_7:I*2NC!IK< M*]@\)?"73_%'@.TU&2YGL]1F:1ED7YD*AB!E3].Q'6O'Z^OO"5D--\(Z19XP M8K2,,/\`:VC/ZYKGQ4W"*Y32E%-ZGC_]B>-/`('FZ-I^OZ6G?[,)64?7&\?C MD"J&F^)_#^N?%32-1GT^UTS3UMFAN(9U01"3;)STP>2O)`YKZ(S7BWC#P[IV MO?&[3M*NHREM=6!:0PX1BP$I#9QURHZ^E<].HIM\RZ&DHVV/5(M#T">)98=+ MTYXV&59;=""/4'%<_P"/?"^F3^!=8%MIMI%-';M*CQP*K`I\W!`]JXZ3X>>, M_!DK7'@_6VN;?[QM)2%)]MI^1C[\&IK;XMM$LNC^--&N-/EDC,;RQQG!!&"2 MAY`]QFH5.5[P=QW6S1X17T%\!?\`D4-1_P"O\_\`HM*^?Y%"R,JL&`)`8=_> MOH#X"_\`(H:C_P!?Y_\`1:5UXK^$94OB/5:***\PZ0HHHH`****`"BBB@`HH MHH`0J&!##(/4&N6UOP+X7U0/)=:):&3&2\:^6Q^I7!-%%7!M/04MCP/Q?HFG M:7-*MG;^4%Z?.S>GJ3ZUQW6BBO6I:QU.<****T25Q!1113L@>P5]!?`7_D4- A1_Z_S_Z+2BBN7%_PPI?$>JT445Y9U!1110`4444`?__9 ` end
Borrowings (Tables)
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Borrowings | The Company’s borrowings consisted of the following at:
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Schedule of Deferred Credit Balance Related to Senior Notes | The following table summarizes the Company’s deferred credit balance:
|
Consolidated Statements of Operations (USD $)
In Thousands, except Per Share data, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
|
Operating revenues: | ||||
Crude oil revenues | $ 19,061 | $ 22,073 | $ 38,601 | $ 47,822 |
Natural gas revenues | 3,699 | 3,287 | 6,700 | 6,833 |
Total oil and natural gas revenues | 22,760 | 25,360 | 45,301 | 54,655 |
Operating expenses: | ||||
Lease operating expenses | 5,384 | 5,246 | 11,142 | 13,484 |
Production taxes | 687 | 575 | 1,226 | 1,122 |
Depreciation, depletion and amortization | 10,654 | 11,844 | 21,696 | 24,033 |
General and administrative | 4,545 | 4,374 | 8,284 | 9,405 |
Accretion expense | 533 | 562 | 1,098 | 1,135 |
Total operating expenses | 21,803 | 22,601 | 43,446 | 49,179 |
Income from operations | 957 | 2,759 | 1,855 | 5,476 |
Other (income) expenses: | ||||
Interest expense | 1,537 | 2,384 | 3,052 | 4,961 |
Gain on early extinguishment of debt | 0 | (1,366) | 0 | (1,366) |
Gain on derivative contracts | (1,981) | (3,505) | (1,563) | (3,575) |
Other income, net | (44) | (157) | (89) | (461) |
Total other (income) expenses, net | (488) | (2,644) | 1,400 | (441) |
Income before income taxes | 1,445 | 5,403 | 455 | 5,917 |
Income tax expense | 663 | 1,610 | 494 | 1,754 |
Income (loss) before equity in earnings of Medusa Spar LLC | 782 | 3,793 | (39) | 4,163 |
Equity in (loss) earnings of Medusa Spar LLC | (24) | 6 | (3) | 124 |
Net income (loss) | 758 | 3,799 | (42) | 4,287 |
Preferred stock dividends | (680) | 0 | (680) | 0 |
Net income (loss) available to common shareholders | $ 78 | $ 3,799 | $ (722) | $ 4,287 |
Net income (loss) per common share: | ||||
Basic | $ 0.00 | $ 0.10 | $ (0.02) | $ 0.11 |
Diluted | $ 0.00 | $ 0.09 | $ (0.02) | $ 0.11 |
Shares used in computing net income (loss) per common share: | ||||
Basic | 40,089 | 39,399 | 39,941 | 39,375 |
Diluted | 40,323 | 40,155 | 39,941 | 40,204 |
Borrowings
|
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
|
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Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Borrowings | Borrowings The Company’s borrowings consisted of the following at:
Senior Secured Revolving Credit Facility (the “Credit Facility”) As of June 30, 2013, the Company’s $200,000 Credit Facility had an associated borrowing base of $75,000 and a maturity of March 15, 2016. Regions Bank serves as the administrative agent for the Credit Facility, which also includes Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. Amounts borrowed under the Credit Facility may not exceed a borrowing base, which is generally reviewed on a semi-annual basis and is then eligible for re-determination. The Credit Facility is secured by mortgages covering the Company’s major producing fields. On May 10, 2013, the Company entered into the second amendment to our Fourth Amended and Restated Credit Agreement that allows the Company to pay quarterly Senior Unsecured Debt and Preferred Equity dividends of $5.5 million per quarter, so long as the Company is not in default under the Credit Facility. The amendment became effective with the receipt of the cash proceeds from the preferred equity offering discussed in Note 9. As of June 30, 2013, no balance was outstanding on the Credit Facility as a portion of the proceeds from the preferred stock offering was used to repay the balance then outstanding. The Credit Facility has an interest rate calculated as the London Interbank Offered Rate (“LIBOR”) plus a tiered rate ranging from 2.5% to 3.0%, which is determined by utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly. 13% Senior Notes due 2016 (“Senior Notes”) and Deferred Credit The Senior Notes’ 13% interest coupon is payable on the last day of each quarter. Certain of the Company’s subsidiaries guarantee the Company’s obligations under the unsecured Senior Notes. The subsidiary guarantors are 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations, and any subsidiaries of the parent company other than the subsidiary guarantors are minor. Upon issuing the Senior Notes in November 2009, the Company recorded as a deferred credit the $31,507 difference between the adjusted carrying amount of the Senior Notes that were exchanged and the principal of the Senior Notes. This deferred credit is being amortized as a reduction of interest expense over the life of the Senior Notes at an 8.5% effective interest rate. The following table summarizes the Company’s deferred credit balance:
Restrictive Covenants The indentures governing our Senior Notes and the Company’s Credit Facility contain various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s Credit Facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at June 30, 2013. |
Borrowings (Senior Secured Revolving Credit Facility) (Details) (USD $)
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0 Months Ended | 6 Months Ended | |||||||
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May 10, 2013
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Jun. 30, 2013
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Dec. 31, 2012
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Jun. 30, 2013
Regions Bank [Member]
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Jun. 30, 2013
Minimum [Member]
Regions Bank [Member]
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Jun. 30, 2013
Maximum [Member]
Regions Bank [Member]
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Jun. 30, 2013
Revolving Credit Facility [Member]
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Dec. 31, 2012
Revolving Credit Facility [Member]
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Jun. 30, 2013
Revolving Credit Facility [Member]
Regions Bank [Member]
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Line of Credit Facility [Line Items] | |||||||||
Maximum borrowing capacity | $ 200,000,000 | ||||||||
Credit Facility borrowing base | 75,000,000 | ||||||||
Amount allowed for payment of debt and dividends | 5,500,000 | ||||||||
Principal outstanding | 96,961,000 | 106,961,000 | 0 | 10,000,000 | |||||
Basis Spread on LIBOR (as a percent) | 2.50% | 3.00% | |||||||
Unused capacity, commitment fee (as a percent) | 0.50% | ||||||||
Balance outstanding on the Credit Facility | $ 0 |
Derivative Instruments and Hedging Activities (Tables)
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Jun. 30, 2013
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following table reflects the fair values of the Company’s derivative instruments for the periods presented (none of which were designated as hedging instruments under ASC 815):
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Offsetting Assets and Liabilities | The following presents the impact of this presentation to the Company’s recognized assets and liabilities at June 30, 2013:
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Schedule of Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance | For the periods indicated, the Company recorded the following related to its derivative instruments that were not designated as accounting hedges:
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Schedule of Derivatives Designated as Hedging Instruments. Gain (Loss) in Statement of Financial Performance | The tables below present the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to crude oil revenues for the effective portion and as an increase (decrease) to other (income) expense for the ineffective portion and amounts excluded from effectiveness testing:
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Schedule of Outstanding Oil and Natural Gas Derivative Contracts | Subsequent Event: Derivative contracts executed subsequent to June 30, 2013 include the following:
In the first quarter of 2013, the Company monetized the remaining portion (covering the period Feb13-Dec13) of its 2013 crude oil collar positions of 40 Bbls per month. The proceeds from this transaction, combined with the proceeds from the sale of the below listed put for 30 Bbls per month, were used to finance the uplift in the crude oil swap for the period Feb13-Dec13. Listed in the table below are the outstanding crude oil and natural gas derivative contracts as of June 30, 2013:
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Derivative Instruments and Hedging Activities (Derivative Positions and Settlements) (Details) (Not Designated as Hedging Instrument [Member], Commodity Contract [Member])
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Jun. 30, 2013
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Natural gas [Member] | Fixed-Price Swap per Instrument of 3 Point 52 Dollars [Member]
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Derivative [Line Items] | |
Average Notional Volumes per Month | 91,000 |
Fixed-Price Swap | 3.52 |
Natural gas [Member] | Average Floor Price per Instrument of $3.00 [Member]
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Derivative [Line Items] | |
Average Notional Volumes per Month | 91,000 |
Put/Call Price | 3.00 |
Natural gas [Member] | Average Ceiling Price per Instrument of $4.75 [Member]
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Derivative [Line Items] | |
Average Notional Volumes per Month | 38,000 |
Put/Call Price | 4.75 |
Crude Oil [Member] | Derivative Average Floor Price per Instrument of 101 Point 30 Dollars and Average Ceiling Price per Instrument of 101 Point 30 Dollars [Member]
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Derivative [Line Items] | |
Average Notional Volumes per Month | 40,000 |
Fixed-Price Swap | 101.30 |
Crude Oil [Member] | Derivative Average Floor Price per Instrument of 93 Point 35 Dollars and Average Ceiling Price per Instrument of 93 Point 35 Dollars [Member]
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Derivative [Line Items] | |
Average Notional Volumes per Month | 30,000 |
Fixed-Price Swap | 93.35 |
Crude Oil [Member] | Average Floor Price per Instrument of $70 [Member]
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Derivative [Line Items] | |
Average Notional Volumes per Month | 30,000 |
Put/Call Price | 70.00 |
Asset Retirement Obligations (Details) (USD $)
In Thousands, unless otherwise specified |
6 Months Ended | |
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Jun. 30, 2013
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Dec. 31, 2012
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Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset retirement obligations, Beginning of period | $ 13,301 | |
Accretion expense | 1,098 | |
Liabilities incurred | 572 | |
Liabilities settled | (397) | |
Revisions to estimate | (1,176) | |
Asset retirement obligations, End of period | 13,398 | |
Less: current asset retirement obligations | 6,223 | 2,336 |
Long-term asset retirement obligations at June 30, 2013 | 7,175 | 10,965 |
Restricted Investments | ||
Restricted investments | $ 3,800 | $ 3,798 |
Fair Value Measurements (Fair Value of Financial Instruments) (Details) (USD $)
In Thousands, unless otherwise specified |
Jun. 30, 2013
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Dec. 31, 2012
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||
13% Senior Notes due 2016 unamortized deferred credit | $ 12,092 | $ 13,707 | ||||
Senior notes principal outstanding | 96,961 | 96,961 | ||||
Senior Notes [Member] | 13% Senior Notes due 2016 [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||
13% Senior Notes due 2016 unamortized deferred credit | 12,092 | 13,707 | ||||
Senior notes principal outstanding | 96,961 | 96,961 | ||||
Carrying (Reported) Amount, Fair Value Disclosure [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||
Total | 109,053 | 120,668 | ||||
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Revolving Credit Facility [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||
Credit Facility | 0 | 10,000 | ||||
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Senior Notes [Member] | 13% Senior Notes due 2016 [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||
13% Senior Notes due 2016 | 109,053 | 110,668 | ||||
Estimate of Fair Value, Fair Value Disclosure [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||
Total | 101,615 | 110,112 | ||||
Estimate of Fair Value, Fair Value Disclosure [Member] | Revolving Credit Facility [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||
Credit Facility | 0 | 10,000 | ||||
Estimate of Fair Value, Fair Value Disclosure [Member] | Senior Notes [Member] | 13% Senior Notes due 2016 [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||
13% Senior Notes due 2016 | $ 101,615 | [1] | $ 100,112 | [1] | ||
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Borrowings (13% Senior Notes due 2016 (“Senior Notes”) and Deferred Credit) (Details) (USD $)
In Thousands, unless otherwise specified |
6 Months Ended | 6 Months Ended | |||
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Jun. 30, 2013
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Jun. 30, 2012
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Dec. 31, 2012
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Jun. 30, 2013
Senior Notes [Member]
13% Senior Notes due 2016 [Member]
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Nov. 30, 2009
Senior Notes [Member]
13% Senior Notes due 2016 [Member]
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Debt Instrument [Line Items] | |||||
Debt instrument, interest rate, stated (as a percent) | 13.00% | ||||
Subsidary guarantor owned (as a percent) | 100.00% | ||||
Gross Carrying Amount | $ 31,507 | ||||
Debt instrument, interest rate, effective (as a percent) | 8.50% | ||||
Accumulated Amortization | 19,415 | 17,800 | 19,415 | ||
Carrying Value | 12,092 | ||||
Amortization Recorded during Current Year as a Reduction of Interest Expense | 1,615 | 1,538 | 1,615 | ||
Estimated Amortization Expected to be Recorded during the Remainder of 2012 | $ 1,684 |
Property Disclosures and Operating Leases
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6 Months Ended |
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Jun. 30, 2013
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Property Acquisition and Operating Leases [Abstract] | |
Property Disclosures and Operating Leases | Property Disclosures and Operating Leases In April 2012, the Company took delivery of a drilling rig for a term of two years to support its horizontal drilling program in the Permian Basin, and on August 1, 2013, the Company contracted an additional drilling rig for a one year term. Lease cost recorded during the three and six months ended June 30, 2013 was $2,280 and $4,551, respectively. Lease payments will approximate $12,601 in 2013 (with $8,050 remaining at June 30, 2013) and $6,941 in 2014. The agreements include early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee, to $5,055 in 2013 and $4,530 in 2014. On June 1, 2013, the Company acquired approximately 2,468 gross (2,186 net) acres in Reagan County, Texas, which is located in the southern portion of the Midland Basin and which is prospective for both horizontal and vertical drilling. The acquisition also included seven gross vertical wells and 1,051 barrels of oil equivalent proved reserves. The purchase price of $11,000 was funded using a portion of the proceeds from the preferred stock offering (discussed in Note 9). |
Derivative Instruments and Hedging Activities
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Jun. 30, 2013
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities Objectives and strategies for using derivative instruments The Company is exposed to fluctuations in realized crude oil and natural gas prices for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its crude oil and natural gas production. The Company primarily utilizes collars, put and call options and swap derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative purposes. Counterparty risk The use of derivative transactions exposes the Company to the risk that a counterparty will be unable to meet its commitments. To manage this risk, the Company’s established counterparties for commodity derivative instruments include a large, well-known financial institution and a large, well-known oil and gas company. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices. Counterparty credit risk is considered when determining a derivative instruments’ fair value; See Note 6 for additional information. The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. Financial statement presentation and settlements In the first quarter of 2013, the Company monetized the remaining portion (covering the period Feb13-Dec13) of its 2013 crude oil collar positions of 40 Bbls per month. The proceeds from this transaction, combined with the proceeds from the sale of the below listed put for 30 Bbls per month, were used to finance the uplift in the crude oil swap for the period Feb13-Dec13. Listed in the table below are the outstanding crude oil and natural gas derivative contracts as of June 30, 2013:
Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a New York Mercantile Exchange (“NYMEX”) price. The fair value of the Company’s derivative instruments, depending on the type of instruments, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. See Note 6 for additional information regarding fair value. The following table reflects the fair values of the Company’s derivative instruments for the periods presented (none of which were designated as hedging instruments under ASC 815):
The Company’s derivative contracts are subject to netting arrangements and, being representative of the way in which the contracts settle, are presented in the balance sheet at their fair values on a net basis based on the underlying commodity being hedged. The following presents the impact of this presentation to the Company’s recognized assets and liabilities at June 30, 2013:
Derivatives not designated as hedging instruments As discussed in the Company’s Form 10-K for the year ended December 31, 2012, the Company elected not to designate as an accounting hedge under FASB ASC 815 any of its derivative contracts executed subsequent to December 31, 2011, nor does it expect to designate future derivative contracts. Any derivative contract not designated as an accounting hedge is carried at its fair value on the balance sheet with both realized and unrealized (mark-to-market) gains or losses on these derivatives recorded on the statement of operations as a component of the Company’s other income and expenses. For the periods indicated, the Company recorded the following related to its derivative instruments that were not designated as accounting hedges:
Derivatives designated as hedging instruments As previously discussed, the Company elected to discontinue hedge accounting at the start of 2012, though certain of the Company’s crude oil derivative contracts designated as cash flow hedges were executed in prior periods and were in effect during 2012. Consequently, these designated contracts were recorded at fair market value with the effective portion of the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity. The cash settlements on contracts for future production were recorded as an increase or decrease in crude oil revenues. Both changes in fair value and cash settlements of ineffective derivative contracts were recognized as derivative expense (income). All contracts previously designated as hedging instruments expired during 2012. The tables below present the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to crude oil revenues for the effective portion and as an increase (decrease) to other (income) expense for the ineffective portion and amounts excluded from effectiveness testing:
Subsequent Event: Derivative contracts executed subsequent to June 30, 2013 include the following:
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Earnings per Share
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Jun. 30, 2013
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Earnings per Share | Earnings Per Share The following table sets forth the computation of basic and diluted earnings per share:
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Derivative Instruments and Hedging Activities (Derivatives Designated as Hedging Instruments/ Derivatives Not Designated as Hedging Instruments) (Details) (USD $)
In Thousands, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
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Jun. 30, 2013
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Jun. 30, 2012
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Jun. 30, 2013
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Jun. 30, 2012
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Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized gain (loss), net | $ 249 | $ 3,897 | ||
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of gain (loss) reclassified from OCI into income (effective portion) | 0 | 512 | 0 | 512 |
Amount of gain (loss) recognized in income (ineffective portion and amount excluded from effectiveness testing) | 0 | 92 | 0 | 322 |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized gain (loss), net | 1,981 | 3,505 | 1,563 | 3,575 |
Commodity Contract [Member] | Natural gas [Member] | Not Designated as Hedging Instrument [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss), net | (156) | 0 | (107) | 0 |
Total gain (loss), net | 329 | (331) | (10) | (331) |
Unrealized gain (loss), net | 485 | (331) | 97 | (331) |
Commodity Contract [Member] | Crude Oil [Member] | Not Designated as Hedging Instrument [Member]
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Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss), net | 849 | 0 | 1,422 | 0 |
Total gain (loss), net | 1,652 | 3,836 | 1,573 | 3,906 |
Unrealized gain (loss), net | $ 803 | $ 3,836 | $ 151 | $ 3,906 |
Fair Value Measurements (Fair Value of Liabilities Measured on Recurring Basis) (Details) (USD $)
In Thousands, unless otherwise specified |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Dec. 31, 2012
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Jun. 30, 2013
Fair Value on a recurring basis [Member]
Level 1 [Member]
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Dec. 31, 2012
Fair Value on a recurring basis [Member]
Level 1 [Member]
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Jun. 30, 2013
Fair Value on a recurring basis [Member]
Level 2 [Member]
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Dec. 31, 2012
Fair Value on a recurring basis [Member]
Level 2 [Member]
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Jun. 30, 2013
Fair Value on a recurring basis [Member]
Level 3 [Member]
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Dec. 31, 2012
Fair Value on a recurring basis [Member]
Level 3 [Member]
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Jun. 30, 2013
Fair Value on a recurring basis [Member]
Estimate of Fair Value, Fair Value Disclosure [Member]
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Dec. 31, 2012
Fair Value on a recurring basis [Member]
Estimate of Fair Value, Fair Value Disclosure [Member]
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Jun. 30, 2013
Fair Value on a nonrecurring basis [Member]
Level 3 [Member]
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Jun. 30, 2013
Current assets - Fair market value of derivatives [Member]
Fair Value on a recurring basis [Member]
Level 1 [Member]
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Dec. 31, 2012
Current assets - Fair market value of derivatives [Member]
Fair Value on a recurring basis [Member]
Level 1 [Member]
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Jun. 30, 2013
Current assets - Fair market value of derivatives [Member]
Fair Value on a recurring basis [Member]
Level 2 [Member]
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Dec. 31, 2012
Current assets - Fair market value of derivatives [Member]
Fair Value on a recurring basis [Member]
Level 2 [Member]
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Jun. 30, 2013
Current assets - Fair market value of derivatives [Member]
Fair Value on a recurring basis [Member]
Level 3 [Member]
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Dec. 31, 2012
Current assets - Fair market value of derivatives [Member]
Fair Value on a recurring basis [Member]
Level 3 [Member]
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Jun. 30, 2013
Current assets - Fair market value of derivatives [Member]
Fair Value on a recurring basis [Member]
Estimate of Fair Value, Fair Value Disclosure [Member]
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Dec. 31, 2012
Current assets - Fair market value of derivatives [Member]
Fair Value on a recurring basis [Member]
Estimate of Fair Value, Fair Value Disclosure [Member]
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Jun. 30, 2013
Other long-term assets [Member]
Fair Value on a recurring basis [Member]
Level 1 [Member]
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Dec. 31, 2012
Other long-term assets [Member]
Fair Value on a recurring basis [Member]
Level 1 [Member]
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Jun. 30, 2013
Other long-term assets [Member]
Fair Value on a recurring basis [Member]
Level 2 [Member]
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Dec. 31, 2012
Other long-term assets [Member]
Fair Value on a recurring basis [Member]
Level 2 [Member]
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Jun. 30, 2013
Other long-term assets [Member]
Fair Value on a recurring basis [Member]
Level 3 [Member]
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Dec. 31, 2012
Other long-term assets [Member]
Fair Value on a recurring basis [Member]
Level 3 [Member]
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Jun. 30, 2013
Other long-term assets [Member]
Fair Value on a recurring basis [Member]
Estimate of Fair Value, Fair Value Disclosure [Member]
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Dec. 31, 2012
Other long-term assets [Member]
Fair Value on a recurring basis [Member]
Estimate of Fair Value, Fair Value Disclosure [Member]
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Jun. 30, 2013
Current Liabilities - Fair Market Value of Derivatives [Member]
Fair Value on a recurring basis [Member]
Level 1 [Member]
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Dec. 31, 2012
Current Liabilities - Fair Market Value of Derivatives [Member]
Fair Value on a recurring basis [Member]
Level 1 [Member]
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Jun. 30, 2013
Current Liabilities - Fair Market Value of Derivatives [Member]
Fair Value on a recurring basis [Member]
Level 2 [Member]
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Dec. 31, 2012
Current Liabilities - Fair Market Value of Derivatives [Member]
Fair Value on a recurring basis [Member]
Level 2 [Member]
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Jun. 30, 2013
Current Liabilities - Fair Market Value of Derivatives [Member]
Fair Value on a recurring basis [Member]
Level 3 [Member]
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Dec. 31, 2012
Current Liabilities - Fair Market Value of Derivatives [Member]
Fair Value on a recurring basis [Member]
Level 3 [Member]
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Jun. 30, 2013
Current Liabilities - Fair Market Value of Derivatives [Member]
Fair Value on a recurring basis [Member]
Estimate of Fair Value, Fair Value Disclosure [Member]
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Dec. 31, 2012
Current Liabilities - Fair Market Value of Derivatives [Member]
Fair Value on a recurring basis [Member]
Estimate of Fair Value, Fair Value Disclosure [Member]
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Jun. 30, 2013
Other long-term liabilities [Member]
Fair Value on a recurring basis [Member]
Level 1 [Member]
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Jun. 30, 2013
Other long-term liabilities [Member]
Fair Value on a recurring basis [Member]
Level 2 [Member]
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Dec. 31, 2012
Other long-term liabilities [Member]
Fair Value on a recurring basis [Member]
Level 2 [Member]
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Jun. 30, 2013
Other long-term liabilities [Member]
Fair Value on a recurring basis [Member]
Level 3 [Member]
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Jun. 30, 2013
Other long-term liabilities [Member]
Fair Value on a recurring basis [Member]
Estimate of Fair Value, Fair Value Disclosure [Member]
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Dec. 31, 2012
Other long-term liabilities [Member]
Fair Value on a recurring basis [Member]
Estimate of Fair Value, Fair Value Disclosure [Member]
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Derivative Assets | |||||||||||||||||||||||||||||||||||||||||
Derivative Assets, Current | $ 1,647 | $ 1,674 | $ 0 | $ 0 | $ 1,647 | $ 1,674 | $ 0 | $ 0 | $ 1,647 | $ 1,674 | |||||||||||||||||||||||||||||||
Derivative Assets, Noncurrent | 0 | 0 | 428 | 250 | 0 | 0 | 428 | 250 | |||||||||||||||||||||||||||||||||
Derivative Assets | 0 | 0 | 2,075 | 1,924 | 0 | 0 | 2,075 | 1,924 | |||||||||||||||||||||||||||||||||
Derivative Liabilities | |||||||||||||||||||||||||||||||||||||||||
Derivative Liabilities, Current | 106 | 125 | 0 | 0 | 106 | 125 | 0 | 0 | 106 | 125 | |||||||||||||||||||||||||||||||
Derivative Liabilities, Noncurrent | 0 | 38 | 116 | 0 | 38 | 116 | |||||||||||||||||||||||||||||||||||
Derivative Liabilities | 0 | 0 | 144 | 241 | 0 | 0 | 144 | 241 | |||||||||||||||||||||||||||||||||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 | 1,931 | 1,683 | 0 | 0 | 1,931 | 1,683 | |||||||||||||||||||||||||||||||||
Asset Retirement Obligation, Fair Value Disclosure | $ 360 |