Document_and_Entity_Informatio
Document and Entity Information (USD $) | 24 Months Ended | ||
Dec. 31, 2014 | Feb. 24, 2015 | Jun. 30, 2014 | |
Document and Entity Information | |||
Entity Registrant Name | Bonanza Creek Energy, Inc. | ||
Entity Central Index Key | 1509589 | ||
Document Type | 10-K | ||
Document Period End Date | 31-Dec-14 | ||
Amendment Flag | FALSE | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $2,310,572,708 | ||
Entity Common Stock, Shares Outstanding | 49,335,032 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $2,584 | $180,582 |
Accounts receivable: | ||
Oil and gas sales | 54,574 | 57,485 |
Joint interest and other | 37,202 | 12,915 |
Prepaid expenses and other | 12,522 | 1,638 |
Inventory of oilfield equipment | 15,353 | 10,696 |
Derivative asset | 86,240 | 858 |
Total current assets | 208,475 | 264,174 |
Property and equipment (successful efforts method), at cost: | ||
Proved properties | 1,924,380 | 1,257,288 |
Less: accumulated depreciation, depletion and amortization | -592,073 | -224,848 |
Total proved properties, net | 1,332,307 | 1,032,440 |
Unproved properties | 206,721 | 45,081 |
Wells in progress | 139,208 | 110,848 |
Natural gas plant, net of accumulated depreciation of $8,457 in 2014 and $5,903 in 2013 | 67,840 | 71,474 |
Other property and equipment, net of accumulated depreciation of $6,087 in 2014 and $2,822 in 2013 | 10,401 | 7,406 |
Oil and gas properties held for sale, net of accumulated depreciation, depletion, and amortization of $- in 2014 and $1,463 in 2013 (note 3) | 360 | |
Total property and equipment, net | 1,756,477 | 1,267,609 |
Long-term derivative asset | 17,765 | 293 |
Other noncurrent assets | 23,372 | 13,859 |
Total assets | 2,006,089 | 1,545,935 |
Current liabilities: | ||
Accounts payable and accrued expenses (Note 5) | 145,788 | 121,665 |
Oil and gas revenue distribution payable | 40,659 | 36,241 |
Contractual obligation for land acquisition | 12,000 | 12,000 |
Derivative liability | 5,320 | |
Total current liabilities | 198,447 | 175,226 |
Long-term liabilities: | ||
Long-term debt | 840,619 | 508,847 |
Contractual obligation for land acquisition | 11,186 | 22,033 |
Ad valorem taxes | 28,635 | 18,867 |
Derivative liability | 1,203 | |
Deferred income taxes, net | 165,667 | 152,681 |
Asset retirement obligations | 21,464 | 11,050 |
Total liabilities | 1,266,018 | 889,907 |
Commitments and contingencies (note 7) | ||
Stockholders' equity: | ||
Preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding | ||
Common stock, $.001 par value, 225,000,000 shares authorized, 41,287,270 and 40,285,919 issued and outstanding in 2014 and 2013, respectively | 41 | 40 |
Additional paid-in capital | 591,511 | 527,752 |
Retained earnings | 148,519 | 128,236 |
Total stockholders' equity | 740,071 | 656,028 |
Total liabilities and stockholders' equity | $2,006,089 | $1,545,935 |
CONSOLIDATED_BALANCE_SHEETS_Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, except Share data, unless otherwise specified | ||
Natural gas plant, accumulated depreciation (in dollars) | $8,457 | $5,903 |
Other property and equipment, accumulated depreciation (in dollars) | 6,087 | 2,822 |
Oil and gas properties held for sale, accumulated depreciation, depletion, and amortization (note 3) (in dollars) | 592,073 | 224,848 |
Preferred stock, par value (in dollars per share) | $0.00 | $0.00 |
Preferred stock, shares authorized | 25,000,000 | 25,000,000 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value (in dollars per share) | $0.00 | $0.00 |
Common stock, shares authorized | 225,000,000 | 225,000,000 |
Common stock, shares issued | 41,287,270 | 41,287,270 |
Common stock, shares outstanding | 40,285,919 | 40,285,919 |
Assets held for sale | ||
Oil and gas properties held for sale, accumulated depreciation, depletion, and amortization (note 3) (in dollars) | $1,463 |
CONSOLIDATED_STATEMENTS_OF_OPE
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Operating net revenues: | |||
Oil and gas sales | $558,633 | $421,860 | $231,205 |
Operating expenses: | |||
Lease operating expense | 72,411 | 47,771 | 30,695 |
Severance and ad valorem taxes | 50,430 | 27,203 | 13,674 |
Exploration | 5,346 | 4,213 | 10,715 |
Depreciation, depletion and amortization | 228,789 | 140,176 | 66,202 |
Impairment of oil and gas properties | 167,592 | 0 | 611 |
General and administrative (including $20,716, $12,638 and $4,483 respectively, of stock compensation) | 81,571 | 55,502 | 31,405 |
Total operating expenses | 606,139 | 274,865 | 153,302 |
Income from operations | -47,506 | 146,995 | 77,903 |
Other income (expense): | |||
Derivative gain (loss) | 121,615 | -12,472 | 924 |
Interest expense | -46,447 | -21,972 | -4,133 |
Other loss | 345 | -43 | -132 |
Total other income (expense) | 75,513 | -34,487 | -3,341 |
Income from continuing operations before taxes | 28,007 | 112,508 | 74,562 |
Current income tax expense | -149 | -248 | -532 |
Deferred income tax expense | -10,876 | -42,678 | -29,459 |
Income from continuing operations | 16,982 | 69,582 | 44,571 |
Discontinued operations (Note 4) | |||
Loss from operations associated with oil and gas properties held for sale | -85 | -644 | -927 |
Gain on sale of oil and gas properties | 5,496 | 4,192 | |
Income tax (expense) benefit | -2,110 | 246 | -1,313 |
Income (loss) from discontinued operations | 3,301 | -398 | 1,952 |
Net income | 20,283 | 69,184 | 46,523 |
Comprehensive income | 20,283 | 69,184 | 46,523 |
Basic net income (loss) per common share: | |||
Income from continuing operations (in dollars per share) | $0.42 | $1.73 | $1.12 |
Income from discontinued operations (in dollars per share) | $0.08 | ($0.01) | $0.05 |
Net income per common share (in dollars per share) | $0.50 | $1.72 | $1.17 |
Basic weighted-average common shares outstanding | 40,139 | 39,337 | 39,052 |
Diluted net income (loss) per common share: | |||
Income from continuing operations (in dollars per share) | $0.41 | $1.72 | $1.12 |
Income from discontinued operations (in dollars per share) | $0.08 | ($0.01) | $0.05 |
Net income per common share (in dollars per share) | $0.49 | $1.71 | $1.17 |
Diluted weighted-average common shares outstanding | 40,290 | 39,403 | 39,052 |
Current income taxes | ($149) | ($248) | ($532) |
CONSOLIDATED_STATEMENTS_OF_OPE1
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Parenthetical) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
CONSOLIDATED STATEMENTS OF OPERATIONS | |||
General and administrative, stock compensation | $20,716 | $12,638 | $4,483 |
CONSOLIDATED_STATEMENTS_OF_STO
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $) | Common Stock | Additional Paid-In Capital | Accumulated Deficit | Total |
In Thousands, except Share data, unless otherwise specified | ||||
Balance at Dec. 31, 2011 | $40 | $515,413 | $12,529 | $527,982 |
Increase (Decrease) in Stockholders' Equity | ||||
Restricted common stock issued, net of excess income tax benefit (in shares) | 736,780 | |||
Restricted common stock forfeited (in shares) | -80,338 | |||
Restricted stock used for tax withholdings | -467 | -467 | ||
Restricted stock used for tax withholdings (in shares) | -18,490 | |||
Offering costs related to sale of common stock | -3 | -3 | ||
Stock based compensation | 4,483 | 4,483 | ||
Net Income | 46,523 | 46,523 | ||
Balance at Dec. 31, 2012 | 40 | 519,426 | 59,052 | 578,518 |
Balance (in shares) at Dec. 31, 2012 | 40,115,536 | |||
Increase (Decrease) in Stockholders' Equity | ||||
Restricted common stock issued, net of excess income tax benefit | 128 | 128 | ||
Restricted common stock issued, net of excess income tax benefit (in shares) | 310,439 | |||
Restricted common stock forfeited (in shares) | -31,817 | |||
Restricted stock used for tax withholdings | -4,440 | -4,440 | ||
Restricted stock used for tax withholdings (in shares) | -108,239 | |||
Stock based compensation | 12,638 | 12,638 | ||
Net Income | 69,184 | 69,184 | ||
Balance at Dec. 31, 2013 | 40 | 527,752 | 128,236 | 656,028 |
Balance (in shares) at Dec. 31, 2013 | 40,285,919 | 41,287,270 | ||
Increase (Decrease) in Stockholders' Equity | ||||
Restricted common stock issued, net of excess income tax benefit (in shares) | 309,458 | |||
Restricted common stock forfeited (in shares) | -31,597 | |||
Restricted stock used for tax withholdings | -6,007 | -6,007 | ||
Restricted stock used for tax withholdings (in shares) | -130,002 | |||
Stock based compensation | 20,716 | 20,716 | ||
Stock issued upon acquisition of oil and gas properties | 1 | 49,050 | 49,051 | |
Stock issued upon acquisition of oil and gas properties (in shares) | 853,492 | |||
Net Income | 20,283 | 20,283 | ||
Balance at Dec. 31, 2014 | $41 | $591,511 | $148,519 | $740,071 |
Balance (in shares) at Dec. 31, 2014 | 41,287,270 | 41,287,270 |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash flows from operating activities: | |||
Net income | $20,283 | $69,184 | $46,523 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 228,856 | 140,547 | 68,445 |
Deferred income taxes | 12,986 | 42,432 | 30,772 |
Impairment of oil and gas properties | 167,592 | 2,259 | |
Stock-based compensation | 20,716 | 12,638 | 4,483 |
Amortization of deferred financing costs | 1,588 | 1,505 | 700 |
Accretion of contractual obligation for land acquisition | 1,153 | 761 | 317 |
Derivative (gain) loss | -121,615 | 12,472 | -924 |
Abandoned lease | 1,709 | 8,379 | |
Gain on sale of oil and gas properties | -5,322 | -4,192 | |
Other | -12 | -8 | 169 |
Changes in current assets and liabilities: | |||
Accounts receivable | -21,376 | -26,315 | -20,738 |
Prepaid expenses and other assets | -10,884 | 1,394 | -1,164 |
Accounts payable and accrued liabilities | 35,392 | 50,897 | 22,769 |
Excess income tax benefit from the vesting of stock awards | -128 | ||
Settlement of asset retirement obligations | -1,637 | -73 | -162 |
Net cash provided by operating activities | 327,720 | 307,015 | 157,636 |
Cash flows from investing activities: | |||
Acquisition of oil and gas properties | -179,566 | -13,797 | -13,920 |
Deposits for acquisitions | -1,549 | ||
Proceeds from sale of oil and gas properties | 6,700 | 9,337 | |
Payments of contractual obligations | -12,000 | -12,000 | |
Exploration and development of oil and gas properties | -641,204 | -417,835 | -281,327 |
Natural gas plant capital expenditures | -282 | -5,202 | -15,788 |
Derivative cash settlements | 12,238 | -11,330 | -725 |
(Increase) decrease in restricted cash | -3,062 | 79 | 253 |
Additions to property and equipment - non oil and gas | -6,269 | -5,138 | -3,107 |
Net cash used in investing activities | -824,994 | -465,223 | -305,277 |
Payments of contractual obligations for land acquisition | -12,000 | -12,000 | |
Cash flows from financing activities: | |||
Proceeds from credit facility | 263,000 | 102,000 | 151,400 |
Payments to credit facility | -230,000 | -260,000 | |
Proceeds from sale of Senior Notes | 300,000 | 500,000 | |
Offering costs related to sale of Senior Notes | -7,070 | -11,721 | |
Payment of employee tax withholdings in exchange for the return of common stock | -6,007 | -4,440 | -467 |
Deferred financing costs | -647 | -445 | -1,111 |
Premium on Senior Notes | 9,000 | ||
Excess income tax benefit from the vesting of stock awards | 128 | ||
Offering costs related to sale of common stock | -3 | ||
Net cash provided by financing activities | 319,276 | 334,522 | 149,819 |
Net change in cash and cash equivalents | -177,998 | 176,314 | 2,178 |
Cash and cash equivalents: | |||
Beginning of period | 180,582 | 4,268 | 2,090 |
End of period | 2,584 | 180,582 | 4,268 |
Supplemental cash flow disclosure: | |||
Cash paid for interest | 36,325 | 12,860 | 2,914 |
Stock issued for the acquisition of oil and gas properties | 49,050 | ||
Cash paid for income taxes | 1,400 | 100 | 400 |
Contractual obligation for land acquisition | 22,033 | 33,272 | 45,272 |
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition | $1,873 | $29,273 | $37,545 |
SUMMARY_OF_SIGNIFICANT_ACCOUNT
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended | |||
Dec. 31, 2014 | ||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||
Description of Operations | ||||
Bonanza Creek Energy, Inc. (the “Company” or “BCEI”) is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. As of December 31, 2014, the Company’s assets and operations are concentrated primarily in the Wattenberg Field in the Rocky Mountains and in the Dorcheat Macedonia Field in southern Arkansas. | ||||
Basis of Presentation | ||||
The consolidated balance sheet includes the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream, LLC, Bonanza Creek Energy Midstream, LLC and Holmes Eastern Company, LLC. All significant intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2014, through the filing date of this report. | ||||
Use of Estimates | ||||
The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. | ||||
Cash and Cash Equivalents | ||||
The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value and cash and cash equivalents approximate fair value due to the short‑term nature of these instruments. | ||||
Accounts Receivable | ||||
The Company’s accounts receivables are generated from oil and gas sales and from joint interest owners on properties that the Company operates. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any allowance may be reasonably estimated. For receivables from joint interest owners, the Company usually has the ability to withhold future revenue disbursements to satisfy the outstanding balance. The Company’s oil and gas receivables are typically collected within one to two months and the Company has experienced minimal bad debts. | ||||
Inventory of Oilfield Equipment | ||||
Inventory consists of material and supplies used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or market, which approximates fair value. | ||||
Oil and Gas Producing Activities | ||||
The Company follows the successful efforts method of accounting for its oil and gas exploration and development costs. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether economically recoverable reserves have been found. If an exploratory well does not find economically recoverable reserves, the costs of drilling the well and other associated costs are charged to dry hole expense. The costs of development wells are capitalized whether the well is productive or nonproductive. Costs incurred to maintain wells and their related equipment and leases as well as operating costs are charged to expense as incurred. Geological and geophysical costs are expensed as incurred. | ||||
Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field‑by‑field basis using the units‑of‑production method based upon proved reserves. | ||||
The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. The factors used to determine fair value are subject to the Company’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows on all developed proved reserves and risk adjusted proved undeveloped, probable and possible reserves, net of estimated operating and development costs, future commodity pricing based on the NYMEX strip price adjusted for basis differential, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. | ||||
The Company assesses its unproved properties periodically for impairment on a property‑by‑property basis, which requires significant judgment. The Company considers the following factors in its assessment of the impairment of unproved properties: | ||||
· | the remaining amount of unexpired term under leases; | |||
· | its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration; | |||
· | its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; | |||
· | its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and | |||
· | its evaluation of the continuing successful results from the application of completion technology in the Niobrara formation by the Company or by other operators in areas adjacent to or near its unproved properties. | |||
Please refer to Note 4—Impairments for additional discussion. | ||||
The Company records the fair value of an asset retirement obligation as an asset and a liability when there is a legal obligation associated with the retirement of a long‑lived asset and the amount can be reasonably estimated. The increase in carrying value is included in proved properties in the accompanying consolidated balance sheets (“accompanying balance sheets”). For additional discussion, please refer to Note 11—Asset Retirement Obligations. | ||||
Gains and losses arising from sales of oil and gas properties will be included in income. However, a partial sale of proved properties within an existing field that does not significantly affect the unit‑of‑production depletion rate will be accounted for as a normal retirement with no gain or loss recognized. The sale of a partial interest within a proved property is accounted for as a recovery of cost. The partial sale of unproved property is accounted for as a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained. | ||||
Natural Gas Plants | ||||
Natural gas plants are recorded at cost and depreciated using the straight‑line method over a 30 year useful life. The Company assesses the facilities for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable and an impairment loss is recorded as necessary. | ||||
Other Property and Equipment | ||||
Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight‑line method over the estimated useful lives of the assets, which range from three to ten years. | ||||
Assets Held for Sale | ||||
Any properties deemed held for sale as of the balance sheet date are presented separately on the accompanying balance sheets at the lower of net book value or fair value less cost to sell. The Company has no assets held for sale at December 31, 2014. At December 31, 2013 the Company had its legacy California assets as held for sale, which is shown within the discontinued operation section of the accompanying consolidated statements of operations and comprehensive income (“accompanying statements of operations”) within Note 3—Discontinued Operations. | ||||
Revenue Recognition | ||||
The Company records revenues, net of royalties, discounts, and allowances, as applicable, from the sales of crude oil and natural gas when delivery to the customer has occurred and title has transferred. Payment is generally received within 30 to 90 days after the date of production. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred. At the end of each month the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company factors in historical performance, quality and transportation differentials, commodity prices, and other factors when deriving revenue estimates. The Company has interests with other producers in certain properties in which case the Company uses the entitlement method to account for gas imbalances. The Company had no gas imbalances as of December 31, 2014, 2013 and 2012. | ||||
For gathering and processing services, the Company either receives fees or commodities from natural gas producers depending on the type of contract. Under the percentage‑of‑proceeds contract type, the Company is paid for its services by keeping a percentage of the NGL produced and a percentage of the residue gas resulting from processing the natural gas. Commodities received are, in turn, sold and recognized as revenue in accordance with the criteria outlined above. | ||||
Income Taxes | ||||
The Company accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. | ||||
Uncertain Tax Positions | ||||
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The tax returns for 2013, 2012 and 2011 are still subject to audit by the Internal Revenue Service. There were no uncertain tax positions. | ||||
Concentrations of Credit Risk | ||||
The Company has maintained cash balances in excess of the Federal Deposit Insurance Corporation (FDIC) insured limit. | ||||
The Company is exposed to credit risk in the event of nonpayment by counterparties whose creditworthiness is continuously evaluated. For the years ended December 31, 2014, 2013 and 2012 Plains Marketing LP accounted for 29%, 37% and 50%, respectively, while Lion Oil Trading & Transportation, Inc. accounted for 19%, 23% and 32%, respectively, of oil and natural gas sales. For the years ended December 31, 2014 and 2013, High Sierra Crude Oil & Marketing accounted for 11% and 15%, respectively, of oil and natural gas sales and an immaterial amount for the year ended December 31, 2012. | ||||
Oil and Gas Derivative Activities | ||||
The Company is exposed to commodity price risk related to oil and gas prices. To mitigate this risk, the Company enters into oil and gas forward contracts. The contracts, which are generally placed with major financial institutions or with counterparties which management believes to be of high credit quality, may take the form of futures contracts, swaps, options, or collars. The oil contracts are indexed to NYMEX WTI prices, and natural gas contracts are indexed to NYMEX HH prices, which have a high degree of historical correlation with actual prices received by the Company, before differentials. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities at fair value. For additional discussion, please refer to Note 13—Derivatives. | ||||
Earnings Per Share | ||||
Earnings per basic and diluted share are calculated under the two‑class method. Pursuant to the two‑class method, the Company’s unvested restricted stock awards with non‑forfeitable rights to dividends are considered participating securities. Under the two‑class method, earnings per basic share is calculated by dividing net income available to shareholders by the weighted‑average number of common shares outstanding during the period. The two‑class method includes an earnings allocation formula that determines earnings per share for each participating security according to undistributed earnings for the period. Net income available to shareholders is reduced by the amount allocated to participating restricted shares to arrive at the earnings allocated to common stock shareholders for purposes of calculating earnings per share. Earnings per diluted share is computed on the basis of the weighted‑average number of common shares outstanding during the period plus the dilutive effect of any potential common shares outstanding during the period using the more dilutive of the treasury method or two‑class method. For additional discussion, please refer to Note 14—Earnings Per Share. | ||||
Stock‑Based Compensation | ||||
The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant‑date fair value of the award. For additional discussion, please refer to Note 9—Stock‑Based Compensation. | ||||
Fair Value of Financial Instruments | ||||
The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, a revolving credit facility, senior notes, and derivative instruments. Cash and cash equivalents, trade receivables, trade payables and accrued liabilities are carried at cost and approximate fair value due to the short‑term nature of these instruments. Our revolving credit facility has a variable interest rate so it approximates fair value. Our senior notes are recorded at cost, and their fair value is disclosed within Note 12—Fair Value Measurements. Derivative instruments are recorded at fair value. The book value of the contractual obligation for land acquisition approximates fair value due to it being discounted at a market-based interest rate. | ||||
Prior Year Reclassifications | ||||
Certain prior year balances have been reclassified to conform to the current year presentation, and such reclassifications had no impact on net income or stockholders’ equity previously reported. | ||||
Recently Issued Accounting Standards | ||||
In April 2014, the FASB issued Update No. 2014-08 - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2014 and is to be applied prospectively. This guidance will be applied by the Company upon future disposal of assets on a prospective basis. | ||||
In May 2014, the FASB issued Update No. 2014-09 - Revenue From Contracts With Customers. The update prescribes two acceptable methods and is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures. | ||||
In June 2014, the FASB issued Update No. 2014-12 - Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period. The guidance relates to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied either prospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures. | ||||
In August 2014, the FASB issued Update No. 2014-15 - Presentation of Financial Statements – Going Concern that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures. | ||||
In November 2014, the FASB issued Update No. 2014-17 – Business Combinations – Pushdown Accounting that gives an acquired entity an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. This guidance was effective on November 18, 2014 for any future change-in-control event. | ||||
ACQUISITIONS
ACQUISITIONS | 12 Months Ended | |||
Dec. 31, 2014 | ||||
ACQUISITIONS | ||||
ACQUISITIONS | NOTE 2—ACQUISITIONS | |||
In July 2014, the Company acquired approximately 34,000 net acres of oil and gas properties, leasehold mineral interests and related assets located in the Wattenberg Field (“Wattenberg Field Acquisition”) from a private operator. The Company paid approximately $174.6 million (inclusive of customary acquisition costs) in cash and issued 853,492 shares of the Company’s common stock valued at $57.47 per share, the market price at the time of closing, for the acquired assets. The Wattenberg Field Acquisition had an effective date of June 1, 2014 and closed on July 8, 2014. The results of operations for the Wattenberg Field Acquisition have been included in the Company’s consolidated financial statements from the date of closing. Pro forma information is not presented as the pro forma results would not have been materially different from the information presented in the accompanying statements of operations. | ||||
The Wattenberg Field Acquisition was recorded using the purchase method of accounting. The following table summarizes the allocation of consideration paid (inclusive of customary acquisition costs) to the tangible assets acquired and liabilities assumed in the Wattenberg Field Acquisition. | ||||
Asset Valuation Amount | ||||
(in thousands) | ||||
Purchase price (1) | $ | 223,678 | ||
Allocation of purchase price: | ||||
Proved properties | $ | 25,014 | ||
Unproved properties | 198,757 | |||
Asset retirement obligation | -93 | |||
Total | $ | 223,678 | ||
On July 31, 2012, the Company acquired leases to approximately 5,600 net acres in the Wattenberg Field from the State of Colorado, State Board of Land Commissioners. The Company paid approximately $12 million at closing, $12 million in July 2013 and $12 million in July 2014. The Company will pay approximately $12 million in July 2015 and July 2016. The future payments were discounted based on our effective borrowing rate to arrive at the purchase price of $57 million. Future payments include imputed interest and are secured by a $24 million letter of credit. Following each payment the amount secured by the letter of credit will be amended to reflect the reduction in obligation. | ||||
DISCONTINUED_OPERATIONS
DISCONTINUED OPERATIONS | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
DISCONTINUED OPERATIONS | ||||||||||
DISCONTINUED OPERATIONS | NOTE 3—DISCONTINUED OPERATIONS | |||||||||
During June of 2012, the Company began marketing, with the intent to sell, all of its oil and gas properties in California classifying them as assets held for sale. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. The Company determined that its intent to sell all of its assets in a region qualified as discontinued operations. The Company sold a majority of the properties for approximately $9.3 million and recorded a gain on the sale of oil and gas properties in the amount of $4.2 million during 2012. The Company sold its remaining property during the first quarter of 2014 for approximately $6.0 million and recorded a gain on the sale of oil and gas properties in the amount of $5.5 million. The carrying amounts of the remaining property included within assets held for sale classified as discontinued operations are presented below. | ||||||||||
As of December 31, | ||||||||||
2014 | 2013 | |||||||||
(in thousands) | ||||||||||
Assets held for sale: | ||||||||||
Oil and gas properties, successful efforts method: | ||||||||||
Proved properties | $ | — | $ | 1,721 | ||||||
Unproved properties | — | 1 | ||||||||
Wells in progress | — | 101 | ||||||||
Total property and equipment | — | 1,823 | ||||||||
Less accumulated depletion, depreciation, and amortization | — | -1,463 | ||||||||
Net property and equipment | $ | — | $ | 360 | ||||||
The current assets and liabilities related to these properties are immaterial. The total revenues, expenses, and income associated with the operation of the oil and gas properties held for sale as discontinued operations are presented below. | ||||||||||
For the Years Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
(in thousands) | ||||||||||
Net revenues: | ||||||||||
Oil and gas sales | $ | 361 | $ | 1,668 | $ | 5,410 | ||||
Operating expenses: | ||||||||||
Lease operating expense | 366 | 1,870 | 2,280 | |||||||
Severance and ad valorem taxes | 13 | 5 | 127 | |||||||
Exploration | — | 66 | 39 | |||||||
Depreciation, depletion and amortization | 67 | 371 | 2,243 | |||||||
Impairment of oil and gas properties | — | — | 1,648 | |||||||
Total operating expenses | 446 | 2,312 | 6,337 | |||||||
Loss from operations associated with oil and gas properties held for sale | $ | -85 | $ | -644 | $ | -927 | ||||
IMPAIRMENTS
IMPAIRMENTS | 12 Months Ended |
Dec. 31, 2014 | |
IMPAIRMENTS | |
IMPAIRMENTS | NOTE 4—IMPAIRMENTS |
For the year ended December 31, 2014, the Company recorded proved property impairments of $127.3 million in the Dorcheat Macedonia Field, due to low commodity prices, $25.0 million of proved property impairments in the McKamie Patton Field due to low commodity prices and natural field decline, and $15.3 million of proved property impairments in the McCallum Field due to low commodity prices. | |
The Company recorded no proved property impairments in 2013. For the year ended December 31, 2012, the Company recorded $611,000 of proved property impairments from continuing operations located in one of the Company’s non‑core southern Arkansas fields and $1.6 million of proved property impairments from discontinued operations located in the Company’s legacy California assets. The impairments of the Company’s legacy assets in California were related to steam flooding results that were lower than expected and the impairment of the non‑core field in southern Arkansas was related to the loss of a lease. | |
OTHER_ASSETS
OTHER ASSETS | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
OTHER ASSETS | |||||||
OTHER ASSETS | NOTE 5—OTHER ASSETS | ||||||
The Company has multiple certificates of deposit at three financial institutions to meet financial bonding requirements in the states of Colorado and Wyoming. | |||||||
The Company has unamortized deferred financing costs related to the bank revolving credit agreement and Senior Notes issuances. | |||||||
As of December 31, | |||||||
2014 | 2013 | ||||||
(in thousands) | |||||||
Certificates of deposit | $ | 228 | $ | 166 | |||
Restricted cash | 3,000 | — | |||||
Deposit for acquisition of oil and gas properties | 1,549 | — | |||||
Deferred financing costs | 18,595 | 13,693 | |||||
Other noncurrent assets | $ | 23,372 | $ | 13,859 | |||
ACCOUNTS_PAYABLE_AND_ACCRUED_E
ACCOUNTS PAYABLE AND ACCRUED EXPENSES | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
ACCOUNTS PAYABLE AND ACCRUED EXPENSES | ||||||||
ACCOUNTS PAYABLE AND ACCRUED EXPENSES | NOTE 6—ACCOUNTS PAYABLE AND ACCRUED EXPENSES | |||||||
Accounts payable and accrued expenses contain the following: | ||||||||
As of December 31, | ||||||||
2014 | 2013 | |||||||
(in thousands) | ||||||||
Drilling and completion costs | $ | 82,844 | $ | 80,971 | ||||
Accounts payable trade | 5,493 | 3,288 | ||||||
Accrued general and administrative cost | 13,541 | 12,720 | ||||||
Lease operating expense | 3,569 | 5,440 | ||||||
Accrued reclamation cost | 162 | 168 | ||||||
Interest | 14,839 | 7,065 | ||||||
Accrued oil and gas derivatives | — | 446 | ||||||
Production and ad valorem taxes and other | 25,340 | 11,567 | ||||||
Total accounts payable and accrued expenses | $ | 145,788 | $ | 121,665 | ||||
LONGTERM_DEBT
LONG-TERM DEBT | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
LONG-TERM DEBT | ||||||||
LONG-TERM DEBT | NOTE 7—LONG‑TERM DEBT | |||||||
Long‑term debt consisted of the following as of December 31, 2014 and 2013: | ||||||||
As of December 31, | ||||||||
2014 | 2013 | |||||||
(in thousands) | ||||||||
Revolving credit facility | $ | 33,000 | $ | — | ||||
6.75% Senior Notes due 2021 | 500,000 | 500,000 | ||||||
Unamortized premium on 6.75% Senior Notes | 7,619 | 8,847 | ||||||
5.75% Senior Notes due 2023 | 300,000 | — | ||||||
Total long-term debt | $ | 840,619 | $ | 508,847 | ||||
Revolving Credit Facility | ||||||||
The revolving credit facility, dated March 29, 2011, as amended, with a syndication of banks, including KeyBank National Association as the administrative agent and issuing lender, provides for borrowings of up to $1 billion. The revolving credit facility provides for interest rates plus an applicable margin to be determined based on LIBOR or a Base Rate, at the Company’s election. LIBOR borrowings bear interest at LIBOR plus 1.50% to 2.50% depending on the utilization level, and the Base Rate borrowings bear interest at the “Bank Prime Rate,” as defined in the revolving credit facility, plus .50% to 1.50%. | ||||||||
On September 30, 2014 the borrowing base under the revolving credit facility was determined to be $600 million, an increase from $450 million (decreased from $525 million following the July 2014 issuance of the Company’s 5.75% Senior Notes). Pursuant to the corresponding amendment, the Company elected to limit bank commitments at $500 million while reserving the option to access, at the Company’s request, the full $600 million prior to the next semi‑annual redetermination. The borrowing base is re‑determined semiannually on May 15 and November 15 and may be re‑determined up to one additional time between such scheduled determinations upon request by the Company or lenders holding 662/3% of the aggregate commitments. Commitment fees on the revolving credit facility range from 0.375% to 0.50%, depending on utilization. The revolving credit facility is collateralized by substantially all the Company’s assets and matures on September 15, 2018. As of December 31, 2014, the Company had $33 million outstanding under the revolving credit facility with an available borrowing capacity of $543 million, if the Company elected to take advantage of the entire borrowing base (without giving effect to any scheduled or interim redetermination), after reduction for the outstanding letter of credit of $24 million. As of December 31, 2013, the Company had no outstanding balance under the revolving credit facility with $414 million available borrowing capacity after reduction for the outstanding letter of credit of $36 million. As of the filing date of this report, the Company had no outstanding balance under the revolving credit facility, with $576 million available borrowing capacity, if the Company elected to take advantage of the entire borrowing base (without giving effect to any scheduled or interim redetermination), after reduction for the outstanding letter of credit of $24 million. For additional discussion on the letter of credit, please refer to Note 2 – Acquisitions. | ||||||||
The revolving credit facility restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets, loans and certain investments and mergers. The revolving credit facility also contains certain financial covenants, which require the maintenance of a minimum current and debt coverage ratios, as defined by the revolving credit facility. The Company was in compliance with all financial and non‑financial covenants as of December 31, 2014 and through the filing date of this report. | ||||||||
5.75% Senior Notes | ||||||||
On July 15, 2014, the Company issued $300 million aggregate principal amount of 5.75% Senior Notes that mature on February 1, 2023. Interest on the 5.75% Senior Notes began accruing on July 15, 2014, and interest is payable on February 1 and August 1 of each year, beginning on February 1, 2015. The 5.75% Senior Notes are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the 5.75% Senior Notes were $293.4 million after deductions of $6.6 million of expenses and underwriting discounts and commissions. The net proceeds were used to pay off the Company’s outstanding credit facility balance and for general corporate purposes, including the Company’s drilling and development program and other capital expenditures. | ||||||||
At any time prior to August 1, 2017, subject to certain limitations, the Company may redeem up to 35% of the aggregate principal amount of the 5.75% Senior Notes at a redemption price of 105.75% of the principal amount, plus accrued and unpaid interest, with an amount of cash not greater than the net cash proceeds of an equity offering. The Company may redeem all or a part of the 5.75% Senior Notes at any time prior to August 1, 2018 subject to a “make-whole” premium and accrued and unpaid interest. On or after August 1, 2018, the Company may redeem all or a part of the 5.75% Senior Notes at the redemption price of 102.875% for 2018, 101.438% for 2019, and 100.0% for 2020 and thereafter, during the twelve month period beginning on August 1 of each applicable year, in each case, plus accrued and unpaid interest. | ||||||||
6.75% Senior Notes | ||||||||
On April 9, 2013, the Company issued $300 million aggregate principal amount of 6.75% Senior Notes that mature on April 15, 2021. Interest on the Senior Notes began accruing on April 9, 2013, and interest is payable on April 15 and October 15 of each year, which began on October 15, 2013. On November 15, 2013, the Company issued an additional $200 million aggregate principal amount of 6.75% Senior Notes as an additional issuance of its existing 6.75% Senior Notes that mature on April 15, 2021. The 6.75% Senior Notes are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Company’s revolving credit facility. The net proceeds from the sale of the 6.75% Senior Notes were $496.8 million after the premium and deduction of $12.2 million of expenses and underwriting discounts and commissions. The net proceeds were used to pay off the Company’s outstanding credit facility balance and for general corporate purposes, including the Company’s drilling and development program and other capital expenditures. | ||||||||
At any time prior to April 15, 2016, the Company may redeem up to 35% of the aggregate principal amount at a redemption price of 106.75% of the principal amount, plus accrued and unpaid interest. The Company may redeem all or a part of the 6.75% Senior Notes at any time prior to April 15, 2017 at the redemption price equal to 100% of the principal amount, plus the applicable “make‑whole” premium and accrued and unpaid interest. On or after April 15, 2017, the Company may redeem all or a part of the 6.75% Senior Notes at the redemption price of 103.375% for 2017, 101.688% for 2018, and 100.0% for 2019 and thereafter, during the twelve month period beginning on April 15 of each applicable year, plus accrued and unpaid interest. | ||||||||
On November 12, 2013 and July 15, 2014, the Company filed automatic registration statements on Form S‑3 to register the Senior Notes and guarantees of the Senior Notes. As of December 31, 2014, all of the existing subsidiaries of the Company are guarantors of the 5.75% Senior Notes and 6.75% Senior Notes, and all such subsidiaries are 100% owned by the Company. The guarantees by the subsidiaries are full and unconditional (except for customary release provisions) and constitute joint and several obligations of the subsidiaries. The Company has no independent assets or operations unrelated to its investments in its consolidated subsidiaries. There are no significant restrictions on the Company’s ability or the ability of any subsidiary guarantor to obtain funds from its subsidiaries by such means as a dividend or loan. | ||||||||
COMMITMENTS_AND_CONTINGENT_LIA
COMMITMENTS AND CONTINGENT LIABILITIES | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
COMMITMENTS AND CONTINGENT LIABILITIES | |||||
COMMITMENTS AND CONTINGENT LIABILITIES | NOTE 8—COMMITMENTS AND CONTINGENT LIABILITIES | ||||
Contingent Liabilities | |||||
From time to time, the Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with accounting authoritative guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations. As of the date of this filing, there were no material pending or overtly threatened legal actions against the Company of which it is aware. | |||||
Commitments | |||||
In October 2014, the Company entered into two purchase and transportation agreements to deliver fixed determinable quantities of crude oil currently anticipated to take effect during the second quarter of 2015 for 12,580 barrels per day over an initial five year term and the third quarter of 2016 for 15,000 barrels per day over an initial seven year term. The aggregate financial commitment fee is approximately $540 million over the initial terms. While the volume commitment may be met with Company volumes or third party volumes, delegated by the Company, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. | |||||
The Company rents office facilities under various non‑cancelable operating lease agreements. The annual minimum payments on the transportation and operating lease agreements for the next five years and total minimum lease payments thereafter are presented below: | |||||
Commitments | |||||
(in thousands) | |||||
2015 | $ | 38,441 | |||
2016 | 68,878 | ||||
2017 | 91,916 | ||||
2018 | 91,990 | ||||
2019 | 92,056 | ||||
2020 and thereafter | 170,132 | ||||
Total | $ | 553,413 | |||
The Company’s office leases extend through 2020. Rent expense for the years ended December 31, 2014, 2013 and 2012 was $2.0 million, $1.4 million and $886,000, respectively. | |||||
STOCKBASED_COMPENSATION
STOCK-BASED COMPENSATION | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
STOCK-BASED COMPENSATION | |||||||||||||||||
STOCK-BASED COMPENSATION | NOTE 9—STOCK‑BASED COMPENSATION | ||||||||||||||||
Management Incentive Plan | |||||||||||||||||
On December 23, 2010, the Company established the Management Incentive Plan (the “Plan”) for the benefit of certain employees, officers and other individuals performing services for the Company. The maximum number of shares of Class B common stock available under the Plan was 10,000 and these shares were converted into 437,787 shares of our restricted common stock upon completion of the Company’s initial public offering. The conversion rate was determined based on a formula factoring in the rate of return to the pre‑IPO common stockholders. The 437,787 shares of common stock that were granted were valued at the IPO stated price of $17.00 per share and vested over a three‑year period. Stock‑based compensation expense of $4.8 million, $2.5 million and $2.5 million was recorded during the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014, all common stock granted under the plan was fully vested with no unrecognized compensation remaining. | |||||||||||||||||
BCEC Investment Trust | |||||||||||||||||
The BCEC Investment Trust was formed to hold shares of our common stock received by Bonanza Creek Energy Company, LLC, our predecessor, in connection with our December 23, 2010 corporate restructuring. On February 5, 2013, 13,825 previously issued shares of our common stock that were fully vested and held by the BCEC Investment Trust were distributed to former employees. While the shares had been issued in December 2010, for accounting purposes, the date of distribution to former employees was considered the grant date, and these shares were valued at the closing price of our common stock on the grant date, which was $34.18 per share. On February 11, 2013, 59,372 previously issued shares of our common stock that were fully vested and held by the BCEC Investment Trust were distributed to certain then current employees. While the shares had been issued in December 2010, for accounting purposes, the date of distribution to employees was considered the grant date, and these shares were valued at the closing price of our common stock on the grant date, which was $34.89 per share. These distributions resulted in a stock‑based compensation expense of $2.5 million for the year ended December 31, 2013. | |||||||||||||||||
Long Term Incentive Plan | |||||||||||||||||
The Company’s 2011 Long Term Incentive Plan has different forms of equity issuances allowed under it as further described in this section. | |||||||||||||||||
Restricted Stock under the Long Term Incentive Plan | |||||||||||||||||
The Company grants shares of restricted stock to directors, eligible employees and officers as a part of its equity incentive plan. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each share of restricted stock represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in one‑third increments over three years. Each share of restricted stock is entitled to a non‑forfeitable dividend, if the Company were to declare one, and has the same voting rights as a share of common stock. Shares of restricted stock are valued at the closing price of the Company’s common stock on the grant date and are recognized as general and administrative expense over the vesting period of the award. | |||||||||||||||||
The Company granted 297,030, 292,396 and 697,500 shares of restricted stock under the LTIP to certain employees during 2014, 2013 and 2012, respectively. The fair value of the restricted stock granted in 2014, 2013 and 2012 was $13.9 million, $12.4 million and $11.8 million, respectively. The Company recognized compensation expense of $13.9 million, $6.9 million and $1.7 million for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014 unrecognized compensation cost was $15.6 million and will be amortized through 2017. | |||||||||||||||||
In 2014, 2013 and 2012, the Company issued 12,919, 18,043 and 33,534 shares, respectively, of restricted common stock under the LTIP to its non‑employee directors. The Company recognized compensation expense of $734,000, $445,000 and $267,000 for the years ended December 31, 2014, 2013 and 2012, respectively. These awards vest approximately one year after issuance. | |||||||||||||||||
A summary of the status and activity of non‑vested restricted stock is presented below: | |||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Weighted- | Weighted- | Weighted- | |||||||||||||||
Average | Average | Average | |||||||||||||||
Restricted | Grant-Date | Restricted | Grant-Date | Restricted | Grant-Date | ||||||||||||
Stock | Fair Value | Stock | Fair Value | Stock | Fair Value | ||||||||||||
Non-vested at beginning of year | 836,002 | $ | 25.11 | 929,336 | $ | 17.06 | 437,787 | $ | 17.00 | ||||||||
Granted | 309,949 | $ | 45.87 | 310,439 | $ | 39.89 | 731,034 | $ | 16.98 | ||||||||
Vested | -524,818 | $ | 25.95 | -371,956 | $ | 17.44 | -159,147 | $ | 17.11 | ||||||||
Forfeited | -31,604 | $ | 32.73 | -31,817 | $ | 24.09 | -80,338 | $ | 15.89 | ||||||||
Non-vested at end of year | 589,529 | $ | 37.66 | 836,002 | $ | 25.11 | 929,336 | $ | 17.06 | ||||||||
Cash flows resulting from excess tax benefits are to be classified as part of cash flows from financing activities. Excess tax benefits are realized tax benefits from tax deductions for vested restricted stock in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock. The Company recorded no excess tax benefits for the years ended December 31, 2014 and 2012. The Company recorded $127,830 for the year ended December 31, 2013 as cash inflows from financing activities. | |||||||||||||||||
Performance Stock Units under the Long Term Incentive Plan | |||||||||||||||||
The Company grants performance stock units (“PSUs”) to certain officers as part of its LTIP. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. PSUs granted prior to 2014 are determined based on the Company’s performance over a three‑year measurement period and vest in their entirety, if at all, at the end of the measurement period. Satisfaction of the performance conditions for the PSUs granted during 2014 are determined at the end of each annual measurement period over the course of the three-year performance cycle in an amount up to two-thirds of the target number of PSUs that are eligible for vesting (such that an amount equal to 200% of the target number of PSUs may be earned during the performance cycle). For all grants, the PSUs will be settled in shares of the Company’s common stock following the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The performance criterion for the PSUs is based on a comparison of the Company’s Total Shareholder Return (“TSR”) for the measurement period compared with the TSRs of a group of peer companies for the measurement period. Compensation expense associated with PSUs is recognized as general and administrative expense over the measurement period. | |||||||||||||||||
The fair value of the PSUs was measured at the grant date with a stochastic process method using the GBM Model. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk‑free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period, as well as the volatilities for each of the Company’s peers. | |||||||||||||||||
During 2014 and 2013, the Company granted 82,312 and 41,622 PSUs, respectively, under the LTIP to certain officers. The fair value of the PSUs granted in 2014 and 2013 was $3.5 million and $1.2 million, respectively. The Company recognized compensation expense of $1.3 million and $340,000 for the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014, unrecognized compensation expense for PSUs was $3.1 million and will be amortized through 2017. | |||||||||||||||||
A summary of the status and activity of non-vested PSUs is presented in the following table: | |||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Weighted- | Weighted- | ||||||||||||||||
Average | Average | ||||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
PSU | Fair Value | PSU | Fair Value | ||||||||||||||
Non-vested at beginning of year(1) | 40,191 | $ | 32.05 | — | $ | — | |||||||||||
Granted(1) | 82,312 | $ | 41.94 | 41,622 | $ | 32.01 | |||||||||||
Vested(2) | -28,330 | $ | 42.50 | — | $ | — | |||||||||||
Forfeited(1) | — | $ | — | -1,431 | $ | 30.85 | |||||||||||
Non-vested at end of year(1) | 94,173 | $ | 37.55 | 40,191 | $ | 32.05 | |||||||||||
-1 | The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition. | ||||||||||||||||
-2 | For the annual measurement period ending December 31, 2014, the 2014 PSU grant vested at a 1.33 multiplier and the earned shares will be released at the end of the three-year performance cycle. | ||||||||||||||||
401(k) Plan | |||||||||||||||||
The Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute up to the contribution limits established under the IRC. The Company matches each employee’s contribution up to six percent of the employee’s base salary. The Company’s matching contributions to the 401(k) Plan were $1.4 million, $837,000, and $589,000 for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||||||||||
ASSET_RETIREMENT_OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
ASSET RETIREMENT OBLIGATIONS | ||||||||
ASSET RETIREMENT OBLIGATIONS | NOTE 11—ASSET RETIREMENT OBLIGATIONS | |||||||
The Company recognizes an estimated liability for future costs to abandon its oil and gas properties. The fair value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties. | ||||||||
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimated costs to abandon the wells, and regulatory requirements. The liability is discounted using the credit‑adjusted risk‑free rate estimated at the time the liability is incurred and ranges from 8% to 11.7%. A reconciliation of the Company’s asset retirement obligation is as follows: | ||||||||
As of December 31, | ||||||||
2014 | 2013 | |||||||
(in thousands) | ||||||||
Beginning of year | $ | 11,218 | $ | 7,334 | ||||
Additional liabilities incurred | 4,190 | 1,067 | ||||||
Accretion expense | 1,382 | 645 | ||||||
Obligations on properties sold | -833 | — | ||||||
Liabilities settled | -557 | -74 | ||||||
Revisions to estimate | 6,226 | 2,246 | ||||||
End of year | $ | 21,626 | $ | 11,218 | ||||
Revisions to the liability could occur due to changes in the estimated economic lives and abandonment costs of the wells along with newly enacted regulatory requirements. The additional liabilities incurred for the year ended December 31, 2014 primarily came from the drilling and completion of new wells and the Wattenberg Field Acquisition. The revisions to estimates for the year ended December 31, 2014 were a result of decreased estimated economic well lives and an increase in estimated abandonment cost on wells that had an asset retirement obligation as of the beginning of the year. | ||||||||
The Company has approximately $162,000 and $168,000 accrued of asset retirement obligations in accounts payable and accrued expenses on the accompanying balance sheets for the years ended December 31, 2014 and 2013, respectively. For additional discussion, please refer to Note 6—Accounts Payable and Accrued Expenses. | ||||||||
FAIR_VALUE_MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
FAIR VALUE MEASUREMENTS | |||||||||||
FAIR VALUE MEASUREMENTS | NOTE 12—FAIR VALUE MEASUREMENTS | ||||||||||
The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: | |||||||||||
Level 1: | Quoted prices are available in active markets for identical assets or liabilities | ||||||||||
Level 2: | Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model‑derived valuations whose inputs are observable or whose significant value drivers are observable | ||||||||||
Level 3: | Significant inputs to the valuation model are unobservable | ||||||||||
Financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. | |||||||||||
The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013 and their classification within the fair value hierarchy: | |||||||||||
As of December 31, 2014 | |||||||||||
Level 1 | Level 2 | Level 3 | |||||||||
(in thousands) | |||||||||||
Derivative assets | $ | — | $ | 104,005 | $ | — | |||||
Derivative liabilities | $ | — | $ | — | $ | — | |||||
As of December 31, 2013 | |||||||||||
Level 1 | Level 2 | Level 3 | |||||||||
(in thousands) | |||||||||||
Derivative assets | $ | — | $ | 1,151 | $ | — | |||||
Derivative liabilities | $ | — | $ | 6,523 | $ | — | |||||
Derivatives | |||||||||||
Fair value of all derivative instruments are estimated with industry‑standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps and collars are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. Presently, all of our derivative arrangements are concentrated with five counterparties all of which are lenders under the Company’s revolving credit facility. | |||||||||||
For the oil and natural gas derivatives outstanding at December 31, 2014, a hypothetical upward or downward shift of 10% per Bbl or MMBtu in the NYMEX forward curve as of December 31, 2014 would change our derivative gain (loss) by $(17.2) million and $15.3 million, respectively. | |||||||||||
Proved Oil and Gas Properties | |||||||||||
Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of risk-adjusted discount rates and price forecasts selected by the Company’s management. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the NYMEX strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. The Company impaired the Dorcheat Macedonia Field which had a carrying value of $519.2 million to its fair value of $391.9 million and recognized an impairment of $127.3 million for the year ended December 31, 2014. The Company impaired the McKamie Patton Field which had a carrying value of $41.0 million to its fair value of $16.0 million and recognized an impairment of $25.0 million for the year ended December 31, 2014. The Company impaired the McCallum Field which had a carrying value of $15.3 million to its fair value of zero and recognized an impairment of $15.3 for the year ended December 31, 2014. There were no proved properties measured at fair value at December 31, 2013. For additional discussion on impairments, please refer to Note 4 – Impairments. | |||||||||||
Unproved Oil and Gas Properties | |||||||||||
Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company uses the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. There were no unproved properties measured at fair value as of December 31, 2014 and 2013. | |||||||||||
Asset Retirement Obligation | |||||||||||
The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit‑adjusted risk‑free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. The Company had $6.2 million of asset retirement obligations recorded at fair value as of December 31, 2014. There were no asset retirement obligations measured at fair value at December 31, 2013. | |||||||||||
Long‑term Debt | |||||||||||
As of December 31, 2014, the Company had $500 million of outstanding 6.75% Senior Notes and $300 million of outstanding 5.75% Senior Notes. The 6.75% Senior Notes are recorded at cost net of the unamortized premium on the accompanying balance sheets at $507.6 million and $508.8 million as of December 31, 2014 and 2013, respectively. The fair value of the 6.75% Senior Notes as of December 31, 2014 and 2013 was $440.0 million and $527.5 million, respectively. The 5.75% Senior Notes are recorded at cost on the accompanying balance sheets of $300.0 million. The fair value of the 5.75% Senior Notes as of December 31, 2014 was $243.0 million. The Senior Notes are measured using Level 1 inputs based on a secondary market trading price. The Company’s revolving credit facility approximates fair value as the applicable interest rates are floating. | |||||||||||
DERIVATIVES
DERIVATIVES | 12 Months Ended | ||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||
DERIVATIVES | |||||||||||||||||||||||
DERIVATIVES | NOTE 13—DERIVATIVES | ||||||||||||||||||||||
The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other‑than‑trading purposes. The Company’s derivatives include swaps and collar arrangements for oil and gas and none of the derivative instruments qualify as having hedging relationships. | |||||||||||||||||||||||
In a typical commodity swap agreement, if the agreed upon published third‑party index price is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. If the index price is below the strike price of our short-puts associated with the Company’s three-way collars, the Company will receive a payment from our hedging counterparty equal to the difference between the strike prices of the short-put and long-put multiplied by the monthly volume associated with the three-way collar | |||||||||||||||||||||||
As of December 31, 2014, and as of the filing date of this report, the Company had the following derivative commodity contracts in place: | |||||||||||||||||||||||
Total | Average | Average | Fair Market | ||||||||||||||||||||
Volumes | Average | Short Floor | Floor | Average | Value of | ||||||||||||||||||
Derivative | (Bbls/MMBtu | Fixed | Price | Price | Ceiling | Asset | |||||||||||||||||
Settlement Period | Instrument | per day) | Price | (Short-Put) | (Long-Put) | Price | (Liability) | ||||||||||||||||
Oil | (in thousands) | ||||||||||||||||||||||
1Q 2015 | Swap | 6,000 | $ | 95.39 | $ | 22,363 | |||||||||||||||||
2Q 2015 | Swap | 5,000 | $ | 94.41 | 17,497 | ||||||||||||||||||
3Q 2015 | Swap | 2,000 | $ | 93.43 | 6,534 | ||||||||||||||||||
4Q 2015 | Swap | 2,000 | $ | 93.43 | 6,170 | ||||||||||||||||||
1Q 2015 | 3-Way Collar | 6,500 | $ | 68.08 | $ | 84.32 | $ | 95.90 | 9,264 | ||||||||||||||
2Q 2015 | 3-Way Collar | 5,500 | $ | 67.73 | $ | 84.09 | $ | 95.16 | 7,275 | ||||||||||||||
3Q 2015 | 3-Way Collar | 6,500 | $ | 68.46 | $ | 84.62 | $ | 95.49 | 7,846 | ||||||||||||||
4Q 2015 | 3-Way Collar | 6,500 | $ | 68.46 | $ | 84.62 | $ | 95.49 | 7,091 | ||||||||||||||
2016 | 3-Way Collar | 5,500 | $ | 70.00 | $ | 85.00 | $ | 96.83 | 17,765 | ||||||||||||||
$ | 101,805 | ||||||||||||||||||||||
Gas | |||||||||||||||||||||||
2015 | 3-Way Collar | 15,000 | $ | 3.50 | $ | 4.00 | $ | 4.75 | $ | 2,200 | |||||||||||||
$ | 2,200 | ||||||||||||||||||||||
Total | $ | 104,005 | |||||||||||||||||||||
Derivative Assets and Liabilities Fair Value | |||||||||||||||||||||||
The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. | |||||||||||||||||||||||
The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of December 31, 2014 and 2013: | |||||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Balance Sheet Location | Fair Value | ||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
Derivative Assets | |||||||||||||||||||||||
Commodity contracts | Current assets | 86,240 | |||||||||||||||||||||
Commodity contracts | Noncurrent assets | 17,765 | |||||||||||||||||||||
Derivative Liabilities | |||||||||||||||||||||||
Commodity contracts | Current liabilities | — | |||||||||||||||||||||
Commodity contracts | Long-term liabilities | — | |||||||||||||||||||||
Total net derivative asset | $ | 104,005 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Balance Sheet Location | Fair Value | ||||||||||||||||||||||
Derivative Assets | (in thousands) | ||||||||||||||||||||||
Commodity contracts | Current assets | $ | 858 | ||||||||||||||||||||
Commodity contracts | Noncurrent assets | 293 | |||||||||||||||||||||
Derivative Liabilities | |||||||||||||||||||||||
Commodity contracts | Current liabilities | -5,320 | |||||||||||||||||||||
Commodity contracts | Long-term liabilities | -1,203 | |||||||||||||||||||||
Total net derivative liability | $ | -5,372 | |||||||||||||||||||||
The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations: | |||||||||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
Derivative cash settlement gain (loss): | |||||||||||||||||||||||
Oil contracts | $ | 11,523 | $ | -11,755 | $ | -1,492 | |||||||||||||||||
Gas contracts | 715 | 425 | 767 | ||||||||||||||||||||
Total derivative cash settlement gain (loss)(1) | $ | 12,238 | $ | -11,330 | $ | -725 | |||||||||||||||||
Change in fair value gain (loss): | $ | 109,377 | $ | -1,142 | $ | 1,649 | |||||||||||||||||
Total derivative gain (loss)(2) | $ | 121,615 | $ | -12,472 | $ | 924 | |||||||||||||||||
-1 | Derivative cash settlement gain (loss) is reported in the derivative cash settlements line item on the accompanying consolidated statements of cash flows within the net cash used in investing activities. | ||||||||||||||||||||||
-2 | Total derivative gain (loss) is reported in the derivative gain (loss) line item on the accompanying consolidated statements of cash flows within the net cash provided by operating activities. | ||||||||||||||||||||||
EARNINGS_PER_SHARE
EARNINGS PER SHARE | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
EARNINGS PER SHARE | |||||||||||
EARNINGS PER SHARE | NOTE 14—EARNINGS PER SHARE | ||||||||||
The Company issues shares of restricted stock entitling the holders to receive non‑forfeitable dividends, if and when, the Company were to declare a dividend, before vesting, thus making the awards participating securities. The awards are included in the calculation of earnings per share under the two‑class method. The two‑class method allocates earnings for the period between common shareholders and unvested participating shareholders. | |||||||||||
The following table sets forth the calculation of earnings per basic and diluted shares from continuing and discontinued operations for the years ended December 31, 2014, 2013 and 2012: | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands, except per share data) | |||||||||||
Income from continuing operations: | |||||||||||
Income from continuing operations | $ | 16,982 | $ | 69,582 | $ | 44,571 | |||||
Less: undistributed earnings to unvested restricted stock | 315 | 1,673 | 826 | ||||||||
Undistributed earnings to common shareholders | 16,667 | 67,909 | 43,745 | ||||||||
Basic income per common share from continuing operations | $ | 0.42 | $ | 1.73 | $ | 1.12 | |||||
Diluted income per common share from continuing operations | $ | 0.41 | $ | 1.72 | $ | 1.12 | |||||
Income (loss) from discontinued operations: | |||||||||||
Income (loss) from discontinued operations | $ | 3,301 | $ | -398 | $ | 1,952 | |||||
Less: undistributed earnings (loss) to unvested restricted stock | 62 | -10 | 36 | ||||||||
Undistributed earnings (loss) to common shareholders | 3,239 | -388 | 1,916 | ||||||||
Basic income (loss) per common share from discontinued operations | $ | 0.08 | $ | -0.01 | $ | 0.05 | |||||
Diluted income (loss) per common share from discontinued operations | $ | 0.08 | $ | -0.01 | $ | 0.05 | |||||
Net income: | |||||||||||
Net income | $ | 20,283 | $ | 69,184 | $ | 46,523 | |||||
Less: undistributed earnings to unvested restricted stock | 377 | 1,663 | 862 | ||||||||
Undistributed earnings to common shareholders | 19,906 | 67,521 | 45,661 | ||||||||
Basic net income per common share | $ | 0.50 | $ | 1.72 | $ | 1.17 | |||||
Diluted net income per common share | $ | 0.49 | $ | 1.71 | $ | 1.17 | |||||
Weighted-average shares outstanding—basic | 40,139 | 39,337 | 39,052 | ||||||||
Add: dilutive effect of contingent PSUs | 151 | 66 | — | ||||||||
Weighted-average shares outstanding—diluted | 40,290 | 39,403 | 39,052 | ||||||||
The Company had no anti‑dilutive shares for the years ended December 31, 2014, 2013 and 2012. | |||||||||||
SUBSEQUENT_EVENT
SUBSEQUENT EVENT | 12 Months Ended |
Dec. 31, 2014 | |
SUBSEQUENT EVENTS: | |
SUBSEQUENT EVENTS | NOTE 15-SUBSEQUENT EVENTS |
Equity Issuance | |
On February 6, 2015, the Company completed a public offering of 8,050,000 shares of its common stock generating net proceeds of $202.6 million after deducting underwriter discounts, commissions and offering expenses of approximately $6.7 million. The Company intends to use net proceeds to repay all of the outstanding borrowings under its revolving credit facility and for general corporate purposes, including the Company’s drilling and development program and other capital expenditures. | |
Three-stream reporting | |
Effective as of January 1, 2015, the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three stream basis, which separately reports NGLs extracted from the natural gas stream and sold as a separate product. The NGL volumes identified by the Company’s gas purchasers are converted to an oil equivalent. The Company believes that this conversion will more accurately convey its production and sales volumes, will allow results to be more comparable with those of its peers and will conform more closely to general industry convention. | |
OIL_AND_GAS_ACTIVITIES
OIL AND GAS ACTIVITIES | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
OIL AND GAS ACTIVITIES | |||||||||||
OIL AND GAS ACTIVITIES | NOTE 16—OIL AND GAS ACTIVITIES | ||||||||||
The Company’s oil and natural gas activities are entirely within the United States. Costs incurred in oil and natural gas producing activities are as follows: | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Acquisition(1) | $ | 228,616 | $ | 13,797 | $ | 58,843 | |||||
Development(2)(3) | 659,633 | 452,455 | 341,135 | ||||||||
Exploration | 5,345 | 2,590 | 4,821 | ||||||||
Total(4) | $ | 893,594 | $ | 468,842 | $ | 404,799 | |||||
-1 | Acquisition costs for unproved properties for the years ended December 31, 2014, 2013 and 2012 were $202.7 million, $3.4 million and $57.0 million, respectively. Acquisition costs for proved properties for the years ended December 31, 2014, 2013 and 2012 were $25.9 million, $10.4 million and $1.8 million, respectively. | ||||||||||
-2 | Development costs include workover costs of $9.8 million, $6.0 million and $4.5 million charged to lease operating expense during the years ended December 31, 2014, 2013 and 2012, respectively. | ||||||||||
-3 | Development costs include gas plant capital expenditures of $0, $4.3 million and $16.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. | ||||||||||
-4 | Includes amounts relating to asset retirement obligations of $6.3 million, $2.8 million and $1.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. | ||||||||||
The net changes in capitalized exploratory well costs are as follows: | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Beginning balance at January 1 | $ | — | $ | — | $ | 5,438 | |||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | — | — | 2,940 | ||||||||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | — | — | — | ||||||||
Capitalized exploratory well costs charged to expense | — | — | -8,378 | ||||||||
Ending balance at December 31 | $ | — | $ | — | $ | — | |||||
During the year ended December 31, 2014, the Company incurred drilling costs for one exploratory well of $1,043,000 and deemed it a dry‑hole by the end of 2014. During the year ended December 31, 2013, the Company incurred drilling costs for one exploratory well of $629,886 and deemed it a dry‑hole by the end of 2013. During the year ended December 31, 2012, the Company incurred $8,378,612 of dry hole expense. | |||||||||||
DISCLOSURES_ABOUT_OIL_AND_GAS_
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | |||||||||||
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | NOTE 17—DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | ||||||||||
The proved reserve estimates at December 31, 2014 are internally generated with an audit performed by NSAI, our third party independent reserve engineers, whereas the December 31, 2013 proved reserve estimates were prepared by NSAI and 2012 proved reserve estimates were prepared by Cawley, Gillespie & Associates, Inc. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. | |||||||||||
All of BCEI’s oil, natural gas liquids, and natural gas reserves are attributable to properties within the United States. A summary of BCEI’s changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2014, 2013 and 2012 are as follows: | |||||||||||
Natural | |||||||||||
Oil | Gas | ||||||||||
(MBbl)(1) | (MMcf) | ||||||||||
Balance—December 31, 2011 | 28,216 | 92,982 | |||||||||
Extensions and discoveries(2) | 12,016 | 50,667 | |||||||||
Sales of minerals in place | -669 | — | |||||||||
Production | -2,529 | -5,475 | |||||||||
Purchases of minerals in place | — | — | |||||||||
Revisions to previous estimates(3) | -3,768 | -19,626 | |||||||||
Balance—December 31, 2012 | 33,266 | 118,548 | |||||||||
Extensions and discoveries(2) | 20,123 | 59,936 | |||||||||
Sales of minerals in place | — | — | |||||||||
Production | -4,257 | -9,976 | |||||||||
Purchases of minerals in place | 1,228 | 3,958 | |||||||||
Revisions to previous estimates(3) | -3,878 | -32,852 | |||||||||
Balance—December 31, 2013 | 46,482 | 139,614 | |||||||||
Extensions and discoveries(2) | 13,222 | 41,963 | |||||||||
Sales of minerals in place | -43 | -73 | |||||||||
Production | -6,018 | -14,114 | |||||||||
Purchases of minerals in place | 709 | 1,214 | |||||||||
Revisions to previous estimates(3) | 3,760 | 19,947 | |||||||||
Balance—December 31, 2014 | 58,112 | 188,551 | |||||||||
Proved developed reserves: | |||||||||||
December 31, 2012 | 15,675 | 48,942 | |||||||||
December 31, 2013 | 22,273 | 59,250 | |||||||||
December 31, 2014 | 30,542 | 94,494 | |||||||||
Proved undeveloped reserves: | |||||||||||
December 31, 2012 | 17,591 | 69,606 | |||||||||
December 31, 2013 | 24,209 | 80,364 | |||||||||
December 31, 2014 | 27,570 | 94,057 | |||||||||
-1 | Natural gas liquids reserves are classified with oil reserves. | ||||||||||
-2 | At December 31, 2014, horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 18,980 MBoe, which is 94% of our total additions of 20,216 MBoe. The remainder of the additions came from our Dorcheat Madedonia Field, Mid‑Continent region. | ||||||||||
At December 31, 2013, horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 28,908 MBoe, which is 96% of our total additions of 30,112 MBoe. The remainder of the additions came from our Dorcheat Madedonia and McKamie Patton Fields, Mid‑Continent region. | |||||||||||
At December 31, 2012, horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 17,380 MBoe, which is 85% of our total additions of 20,461 MBoe. The remainder of the additions were the result of vertical drilling during the year in the Wattenberg Field and proved developed non‑producing and proved undeveloped reserve additions in the Dorcheat Macedonia Field, Mid‑Continent region. | |||||||||||
-3 | As of December 31, 2014, we revised our proved reserves upward by 7,333 Mboe, excluding pricing revisions, due primarily to the addition of 49 new proved undeveloped locations on 80-acre spacing, directly offsetting economic proved producing wells drilled prior to 2014, 21 diagonal offsets to economic proved producing wells and 12 proved undeveloped locations greater than one offset to economic proved producing wells but within developed areas and surrounded by proved producing wells. As of December 31, 2014, approximately 70% of our horizontal development in the Wattenberg Field was in the Niobrara B formation. A total of 119 horizontal proved undeveloped locations were added to the proved reserves at December 31, 2014 to either extensions and discoveries or revisions to previous estimates. The positive engineering revision was offset by a small negative performance revision of approximately 540 MBoe. A small negative pricing revision of 248 MBoe resulted from a decrease in average commodity price from $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013 to $94.99 per Bbl WTI and $4.35 per MMBtu HH for the year ended December 31, 2014. | ||||||||||
At December 31, 2013, we revised our proved reserves downward by 9,867 MBoe, excluding pricing revisions, due primarily to the change in focus from vertical to horizontal development in the Watterberg Field. This accounted for 69% of the downward revision and included the elimination of 45 net vertical locations from proved undeveloped, the elimination of all proved non‑ producing reserves associated with vertical well refracs and recompletions, and lower performance from the vertical producers due to increased line pressure. The high line pressure also affected the horizontal reserves creating a negative revision of 1.8 MMBoe, or 18% of the total downward revision. We had a small positive pricing revision of 514 MBoe from an increase in commodity price from $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012 to $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013. | |||||||||||
At December 31, 2012, we revised our proved reserves downward by 6,938 MBoe, excluding pricing revisions, due primarily to a combination of eliminating 50 locations from proved undeveloped reserves as a result of a change in focus from vertical to horizontal development and lower performance than expected from our vertical producers in our Wattenberg Field, Rocky Mountain region. A small negative pricing revision of 101 MBoe resulted from a decrease in commodity price from $96.19 per Bbl WTI and $4.12 per MMBtu HH for the year ended December 31, 2011 to $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012. | |||||||||||
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with accounting authoritative guidance. Future cash inflows were computed by applying prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year‑end, based on costs and assuming continuation of existing economic conditions. | |||||||||||
Future income tax expenses are calculated by applying appropriate year‑end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves. Future income tax expenses give effect to permanent differences, tax credits and loss carry forwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of BCEI’s oil and natural gas properties. | |||||||||||
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Future cash flows | $ | 5,780,745 | $ | 4,799,149 | $ | 3,367,465 | |||||
Future production costs | -2,257,572 | -1,681,419 | -1,037,537 | ||||||||
Future development costs | -952,041 | -776,512 | -684,160 | ||||||||
Future income tax expense | -457,625 | -576,024 | -298,201 | ||||||||
Future net cash flows | 2,113,507 | 1,765,194 | 1,347,567 | ||||||||
10% annual discount for estimated timing of cash flows | -1,006,131 | -839,911 | -664,126 | ||||||||
Standardized measure of discounted future net cash flows | $ | 1,107,376 | $ | 925,283 | $ | 683,441 | |||||
Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end. | |||||||||||
The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Beginning of period | $ | 925,283 | $ | 683,441 | $ | 666,186 | |||||
Sale of oil and gas produced, net of production costs | -435,792 | -346,679 | -189,840 | ||||||||
Net changes in prices and production costs | -331,930 | 94,881 | -81,527 | ||||||||
Extensions, discoveries and improved recoveries | 492,144 | 571,384 | 310,595 | ||||||||
Development costs incurred | 116,958 | 67,063 | 161,527 | ||||||||
Changes in estimated development cost | -15,131 | 127,034 | -9,404 | ||||||||
Purchases of mineral in place | 30,919 | 5,442 | — | ||||||||
Sales of mineral in place | -1,173 | — | -14,909 | ||||||||
Revisions of previous quantity estimates | 122,169 | -212,034 | -156,867 | ||||||||
Net change in income taxes | 68,856 | -150,704 | -23,441 | ||||||||
Accretion of discount | 122,722 | 83,468 | 79,398 | ||||||||
Changes in production rates and other | 12,351 | 1,987 | -58,277 | ||||||||
End of period | $ | 1,107,376 | $ | 925,283 | $ | 683,441 | |||||
The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2014, 2013 and 2012 were calculated using the twelve‑month arithmetic average of first‑day‑of‑the‑month price inclusive of adjustments for quality and location. | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
Oil (per Bbl) | $ | 84.28 | $ | 92.03 | $ | 91.04 | |||||
Gas (per Mcf) | $ | 5.24 | $ | 4.67 | $ | 3.78 | |||||
QUARTERLY_FINANCIAL_DATA_UNAUD
QUARTERLY FINANCIAL DATA (UNAUDITED) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
QUARTERLY FINANCIAL DATA (UNAUDITED) | |||||||||||||
QUARTERLY FINANCIAL DATA (UNAUDITED) | NOTE 18—QUARTERLY FINANCIAL DATA (UNAUDITED) | ||||||||||||
The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2014 and 2013: | |||||||||||||
Three Months Ended | |||||||||||||
31-Mar | 30-Jun | 30-Sep | 31-Dec | ||||||||||
(in thousands, except per share data) | |||||||||||||
2014 | |||||||||||||
Oil and gas sales(2) | $ | 127,395 | $ | 151,682 | $ | 156,371 | $ | 123,185 | |||||
Operating profit(1)(2) | 58,432 | 63,284 | 59,579 | 25,708 | |||||||||
Net income (loss) | 13,531 | 1,158 | 48,782 | -43,188 | |||||||||
Basic net income (loss) per common share | $ | 0.34 | $ | 0.03 | $ | 1.18 | $ | -1.05 | |||||
Diluted net income (loss) per common share | $ | 0.34 | $ | 0.03 | $ | 1.18 | $ | -1.06 | |||||
2013 | |||||||||||||
Oil and gas sales(2) | $ | 78,307 | $ | 84,517 | $ | 125,973 | $ | 133,063 | |||||
Operating profit(1)(2) | 39,001 | 36,750 | 68,179 | 62,780 | |||||||||
Net income | 11,256 | 14,715 | 17,781 | 25,432 | |||||||||
Basic net income per common share | $ | 0.28 | $ | 0.36 | $ | 0.44 | $ | 0.64 | |||||
Diluted net income per common share | $ | 0.28 | $ | 0.36 | $ | 0.44 | $ | 0.63 | |||||
-1 | Oil and gas sales less lease operating expense, severance and ad valorem taxes, depreciation, and depletion and amortization. | ||||||||||||
-2 | Amounts reflect results for continuing operations and exclude results for discontinued operations related to non‑core properties in California sold or held for sale as of December 31, 2014 and 2013. | ||||||||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||
Basis of Presentation | Basis of Presentation | |||
The consolidated balance sheet includes the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream, LLC, Bonanza Creek Energy Midstream, LLC and Holmes Eastern Company, LLC. All significant intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2014, through the filing date of this report. | ||||
Use of Estimates | Use of Estimates | |||
The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. | ||||
Cash and Cash Equivalents | Cash and Cash Equivalents | |||
The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value and cash and cash equivalents approximate fair value due to the short‑term nature of these instruments. | ||||
Accounts Receivable | Accounts Receivable | |||
The Company’s accounts receivables are generated from oil and gas sales and from joint interest owners on properties that the Company operates. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any allowance may be reasonably estimated. For receivables from joint interest owners, the Company usually has the ability to withhold future revenue disbursements to satisfy the outstanding balance. The Company’s oil and gas receivables are typically collected within one to two months and the Company has experienced minimal bad debts. | ||||
Inventory of Oilfield Equipment | Inventory of Oilfield Equipment | |||
Inventory consists of material and supplies used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or market, which approximates fair value. | ||||
Oil and Gas Producing Activities | Oil and Gas Producing Activities | |||
The Company follows the successful efforts method of accounting for its oil and gas exploration and development costs. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether economically recoverable reserves have been found. If an exploratory well does not find economically recoverable reserves, the costs of drilling the well and other associated costs are charged to dry hole expense. The costs of development wells are capitalized whether the well is productive or nonproductive. Costs incurred to maintain wells and their related equipment and leases as well as operating costs are charged to expense as incurred. Geological and geophysical costs are expensed as incurred. | ||||
Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field‑by‑field basis using the units‑of‑production method based upon proved reserves. | ||||
The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. The factors used to determine fair value are subject to the Company’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows on all developed proved reserves and risk adjusted proved undeveloped, probable and possible reserves, net of estimated operating and development costs, future commodity pricing based on the NYMEX strip price adjusted for basis differential, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. | ||||
The Company assesses its unproved properties periodically for impairment on a property‑by‑property basis, which requires significant judgment. The Company considers the following factors in its assessment of the impairment of unproved properties: | ||||
· | the remaining amount of unexpired term under leases; | |||
· | its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration; | |||
· | its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; | |||
· | its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and | |||
· | its evaluation of the continuing successful results from the application of completion technology in the Niobrara formation by the Company or by other operators in areas adjacent to or near its unproved properties. | |||
Please refer to Note 4—Impairments for additional discussion. | ||||
The Company records the fair value of an asset retirement obligation as an asset and a liability when there is a legal obligation associated with the retirement of a long‑lived asset and the amount can be reasonably estimated. The increase in carrying value is included in proved properties in the accompanying consolidated balance sheets (“accompanying balance sheets”). For additional discussion, please refer to Note 11—Asset Retirement Obligations. | ||||
Gains and losses arising from sales of oil and gas properties will be included in income. However, a partial sale of proved properties within an existing field that does not significantly affect the unit‑of‑production depletion rate will be accounted for as a normal retirement with no gain or loss recognized. The sale of a partial interest within a proved property is accounted for as a recovery of cost. The partial sale of unproved property is accounted for as a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained. | ||||
Natural Gas Plant | Natural Gas Plants | |||
Natural gas plants are recorded at cost and depreciated using the straight‑line method over a 30 year useful life. The Company assesses the facilities for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable and an impairment loss is recorded as necessary. | ||||
Other Property and Equipment | Other Property and Equipment | |||
Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight‑line method over the estimated useful lives of the assets, which range from three to ten years. | ||||
Assets Held for Sale | Assets Held for Sale | |||
Any properties deemed held for sale as of the balance sheet date are presented separately on the accompanying balance sheets at the lower of net book value or fair value less cost to sell. The Company has no assets held for sale at December 31, 2014. At December 31, 2013 the Company had its legacy California assets as held for sale, which is shown within the discontinued operation section of the accompanying consolidated statements of operations and comprehensive income (“accompanying statements of operations”) within Note 3—Discontinued Operations. | ||||
Revenue Recognition | Revenue Recognition | |||
The Company records revenues, net of royalties, discounts, and allowances, as applicable, from the sales of crude oil and natural gas when delivery to the customer has occurred and title has transferred. Payment is generally received within 30 to 90 days after the date of production. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred. At the end of each month the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company factors in historical performance, quality and transportation differentials, commodity prices, and other factors when deriving revenue estimates. The Company has interests with other producers in certain properties in which case the Company uses the entitlement method to account for gas imbalances. The Company had no gas imbalances as of December 31, 2014, 2013 and 2012. | ||||
For gathering and processing services, the Company either receives fees or commodities from natural gas producers depending on the type of contract. Under the percentage‑of‑proceeds contract type, the Company is paid for its services by keeping a percentage of the NGL produced and a percentage of the residue gas resulting from processing the natural gas. Commodities received are, in turn, sold and recognized as revenue in accordance with the criteria outlined above. | ||||
Income Taxes | Income Taxes | |||
The Company accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. | ||||
Uncertain Tax Positions | Uncertain Tax Positions | |||
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The tax returns for 2013, 2012 and 2011 are still subject to audit by the Internal Revenue Service. There were no uncertain tax positions. | ||||
Concentrations of Credit Risk | Concentrations of Credit Risk | |||
The Company has maintained cash balances in excess of the Federal Deposit Insurance Corporation (FDIC) insured limit. | ||||
The Company is exposed to credit risk in the event of nonpayment by counterparties whose creditworthiness is continuously evaluated. For the years ended December 31, 2014, 2013 and 2012 Plains Marketing LP accounted for 29%, 37% and 50%, respectively, while Lion Oil Trading & Transportation, Inc. accounted for 19%, 23% and 32%, respectively, of oil and natural gas sales. For the years ended December 31, 2014 and 2013, High Sierra Crude Oil & Marketing accounted for 11% and 15%, respectively, of oil and natural gas sales and an immaterial amount for the year ended December 31, 2012. | ||||
Oil and Gas Derivative Activities | Oil and Gas Derivative Activities | |||
The Company is exposed to commodity price risk related to oil and gas prices. To mitigate this risk, the Company enters into oil and gas forward contracts. The contracts, which are generally placed with major financial institutions or with counterparties which management believes to be of high credit quality, may take the form of futures contracts, swaps, options, or collars. The oil contracts are indexed to NYMEX WTI prices, and natural gas contracts are indexed to NYMEX HH prices, which have a high degree of historical correlation with actual prices received by the Company, before differentials. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities at fair value. For additional discussion, please refer to Note 13—Derivatives. | ||||
Earnings Per Share | Earnings Per Share | |||
Earnings per basic and diluted share are calculated under the two‑class method. Pursuant to the two‑class method, the Company’s unvested restricted stock awards with non‑forfeitable rights to dividends are considered participating securities. Under the two‑class method, earnings per basic share is calculated by dividing net income available to shareholders by the weighted‑average number of common shares outstanding during the period. The two‑class method includes an earnings allocation formula that determines earnings per share for each participating security according to undistributed earnings for the period. Net income available to shareholders is reduced by the amount allocated to participating restricted shares to arrive at the earnings allocated to common stock shareholders for purposes of calculating earnings per share. Earnings per diluted share is computed on the basis of the weighted‑average number of common shares outstanding during the period plus the dilutive effect of any potential common shares outstanding during the period using the more dilutive of the treasury method or two‑class method. For additional discussion, please refer to Note 14—Earnings Per Share. | ||||
Stock-Based Compensation | Stock‑Based Compensation | |||
The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant‑date fair value of the award. For additional discussion, please refer to Note 9—Stock‑Based Compensation. | ||||
Fair Value of Financial Instruments | Fair Value of Financial Instruments | |||
The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, a revolving credit facility, senior notes, and derivative instruments. Cash and cash equivalents, trade receivables, trade payables and accrued liabilities are carried at cost and approximate fair value due to the short‑term nature of these instruments. Our revolving credit facility has a variable interest rate so it approximates fair value. Our senior notes are recorded at cost, and their fair value is disclosed within Note 12—Fair Value Measurements. Derivative instruments are recorded at fair value. The book value of the contractual obligation for land acquisition approximates fair value due to it being discounted at a market-based interest rate. | ||||
Prior Year Reclassifications | Prior Year Reclassifications | |||
Certain prior year balances have been reclassified to conform to the current year presentation, and such reclassifications had no impact on net income or stockholders’ equity previously reported. | ||||
Recently Issued Accounting Standards | Recently Issued Accounting Standards | |||
In April 2014, the FASB issued Update No. 2014-08 - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2014 and is to be applied prospectively. This guidance will be applied by the Company upon future disposal of assets on a prospective basis. | ||||
In May 2014, the FASB issued Update No. 2014-09 - Revenue From Contracts With Customers. The update prescribes two acceptable methods and is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures. | ||||
In June 2014, the FASB issued Update No. 2014-12 - Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period. The guidance relates to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied either prospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures. | ||||
In August 2014, the FASB issued Update No. 2014-15 - Presentation of Financial Statements – Going Concern that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures. | ||||
In November 2014, the FASB issued Update No. 2014-17 – Business Combinations – Pushdown Accounting that gives an acquired entity an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. This guidance was effective on November 18, 2014 for any future change-in-control event. | ||||
ACQUISITIONS_Tables
ACQUISITIONS (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
ACQUISITIONS | ||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | ||||
Asset Valuation Amount | ||||
(in thousands) | ||||
Purchase price (1) | $ | 223,678 | ||
Allocation of purchase price: | ||||
Proved properties | $ | 25,014 | ||
Unproved properties | 198,757 | |||
Asset retirement obligation | -93 | |||
Total | $ | 223,678 | ||
DISCONTINUED_OPERATIONS_Tables
DISCONTINUED OPERATIONS (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
DISCONTINUED OPERATIONS | ||||||||||
Schedule of the carrying amounts of the remaining properties included within assets held for sale classified as discontinued operations | ||||||||||
As of December 31, | ||||||||||
2014 | 2013 | |||||||||
(in thousands) | ||||||||||
Assets held for sale: | ||||||||||
Oil and gas properties, successful efforts method: | ||||||||||
Proved properties | $ | — | $ | 1,721 | ||||||
Unproved properties | — | 1 | ||||||||
Wells in progress | — | 101 | ||||||||
Total property and equipment | — | 1,823 | ||||||||
Less accumulated depletion, depreciation, and amortization | — | -1,463 | ||||||||
Net property and equipment | $ | — | $ | 360 | ||||||
Schedule of revenues and expenses, and the income associated with the operation of the oil and gas properties held for sale | ||||||||||
For the Years Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
(in thousands) | ||||||||||
Net revenues: | ||||||||||
Oil and gas sales | $ | 361 | $ | 1,668 | $ | 5,410 | ||||
Operating expenses: | ||||||||||
Lease operating expense | 366 | 1,870 | 2,280 | |||||||
Severance and ad valorem taxes | 13 | 5 | 127 | |||||||
Exploration | — | 66 | 39 | |||||||
Depreciation, depletion and amortization | 67 | 371 | 2,243 | |||||||
Impairment of oil and gas properties | — | — | 1,648 | |||||||
Total operating expenses | 446 | 2,312 | 6,337 | |||||||
Loss from operations associated with oil and gas properties held for sale | $ | -85 | $ | -644 | $ | -927 | ||||
OTHER_ASSETS_Tables
OTHER ASSETS (Tables) | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
OTHER ASSETS | |||||||
Schedule of other assets | |||||||
As of December 31, | |||||||
2014 | 2013 | ||||||
(in thousands) | |||||||
Certificates of deposit | $ | 228 | $ | 166 | |||
Restricted cash | 3,000 | — | |||||
Deposit for acquisition of oil and gas properties | 1,549 | — | |||||
Deferred financing costs | 18,595 | 13,693 | |||||
Other noncurrent assets | $ | 23,372 | $ | 13,859 | |||
ACCOUNTS_PAYABLE_AND_ACCRUED_E1
ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
ACCOUNTS PAYABLE AND ACCRUED EXPENSES | ||||||||
Schedule of accounts payable and accrued expenses | ||||||||
As of December 31, | ||||||||
2014 | 2013 | |||||||
(in thousands) | ||||||||
Drilling and completion costs | $ | 82,844 | $ | 80,971 | ||||
Accounts payable trade | 5,493 | 3,288 | ||||||
Accrued general and administrative cost | 13,541 | 12,720 | ||||||
Lease operating expense | 3,569 | 5,440 | ||||||
Accrued reclamation cost | 162 | 168 | ||||||
Interest | 14,839 | 7,065 | ||||||
Accrued oil and gas derivatives | — | 446 | ||||||
Production and ad valorem taxes and other | 25,340 | 11,567 | ||||||
Total accounts payable and accrued expenses | $ | 145,788 | $ | 121,665 | ||||
LONGTERM_DEBT_Tables
LONG-TERM DEBT (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
LONG-TERM DEBT | ||||||||
Schedule of long-term debt | ||||||||
As of December 31, | ||||||||
2014 | 2013 | |||||||
(in thousands) | ||||||||
Revolving credit facility | $ | 33,000 | $ | — | ||||
6.75% Senior Notes due 2021 | 500,000 | 500,000 | ||||||
Unamortized premium on 6.75% Senior Notes | 7,619 | 8,847 | ||||||
5.75% Senior Notes due 2023 | 300,000 | — | ||||||
Total long-term debt | $ | 840,619 | $ | 508,847 | ||||
COMMITMENTS_AND_CONTINGENT_LIA1
COMMITMENTS AND CONTINGENT LIABILITIES (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
COMMITMENTS AND CONTINGENT LIABILITIES | |||||
Schedule of annual minimum payments for the next five years and total minimum lease payments thereafter | |||||
Commitments | |||||
(in thousands) | |||||
2015 | $ | 38,441 | |||
2016 | 68,878 | ||||
2017 | 91,916 | ||||
2018 | 91,990 | ||||
2019 | 92,056 | ||||
2020 and thereafter | 170,132 | ||||
Total | $ | 553,413 | |||
STOCKBASED_COMPENSATION_Tables
STOCK-BASED COMPENSATION (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
STOCK-BASED COMPENSATION | |||||||||||||||||
Summary of the status and activity of non-vested restricted stock | |||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Weighted- | Weighted- | Weighted- | |||||||||||||||
Average | Average | Average | |||||||||||||||
Restricted | Grant-Date | Restricted | Grant-Date | Restricted | Grant-Date | ||||||||||||
Stock | Fair Value | Stock | Fair Value | Stock | Fair Value | ||||||||||||
Non-vested at beginning of year | 836,002 | $ | 25.11 | 929,336 | $ | 17.06 | 437,787 | $ | 17.00 | ||||||||
Granted | 309,949 | $ | 45.87 | 310,439 | $ | 39.89 | 731,034 | $ | 16.98 | ||||||||
Vested | -524,818 | $ | 25.95 | -371,956 | $ | 17.44 | -159,147 | $ | 17.11 | ||||||||
Forfeited | -31,604 | $ | 32.73 | -31,817 | $ | 24.09 | -80,338 | $ | 15.89 | ||||||||
Non-vested at end of year | 589,529 | $ | 37.66 | 836,002 | $ | 25.11 | 929,336 | $ | 17.06 | ||||||||
Summary of the status and activity of PSUs | |||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Weighted- | Weighted- | ||||||||||||||||
Average | Average | ||||||||||||||||
Grant Date | Grant Date | ||||||||||||||||
PSU | Fair Value | PSU | Fair Value | ||||||||||||||
Non-vested at beginning of year(1) | 40,191 | $ | 32.05 | — | $ | — | |||||||||||
Granted(1) | 82,312 | $ | 41.94 | 41,622 | $ | 32.01 | |||||||||||
Vested(2) | -28,330 | $ | 42.50 | — | $ | — | |||||||||||
Forfeited(1) | — | $ | — | -1,431 | $ | 30.85 | |||||||||||
Non-vested at end of year(1) | 94,173 | $ | 37.55 | 40,191 | $ | 32.05 | |||||||||||
-1 | The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition. | ||||||||||||||||
-2 | For the annual measurement period ending December 31, 2014, the 2014 PSU grant vested at a 1.33 multiplier and the earned shares will be released at the end of the three-year performance cycle. | ||||||||||||||||
INCOME_TAXES_Tables
INCOME TAXES (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
INCOME TAXES | |||||||||||
Schedule of provision for income taxes | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Current tax expense | |||||||||||
Federal | $ | 165 | $ | 122 | $ | 289 | |||||
State | -16 | 126 | 243 | ||||||||
Deferred tax expense | 12,986 | 42,432 | 30,772 | ||||||||
Total income tax expense | $ | 13,135 | $ | 42,680 | $ | 31,304 | |||||
Schedule of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities that give rise to net deferred tax liability | |||||||||||
As of December 31, | |||||||||||
2014 | 2013 | ||||||||||
(in thousands) | |||||||||||
Deferred tax liabilities: | |||||||||||
Oil and gas properties | $ | 201,635 | $ | 195,776 | |||||||
Derivative asset | 40,060 | — | |||||||||
Total deferred tax liabilities | 241,695 | 195,776 | |||||||||
Deferred tax assets: | |||||||||||
Federal and state tax net operating loss carryforward | 59,952 | 31,289 | |||||||||
Reclamation costs | 8,344 | 4,311 | |||||||||
Stock compensation | 3,845 | 2,617 | |||||||||
Derivative liability | — | 1,833 | |||||||||
AMT credit | 812 | 776 | |||||||||
State bonus depreciation addback | 2,083 | 1,938 | |||||||||
Other long-term liabilities | 992 | 331 | |||||||||
Total deferred tax assets | 76,028 | 43,095 | |||||||||
Total non-current net deferred tax liability | $ | 165,667 | $ | 152,681 | |||||||
Schedule of reconciliation of the Company's statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, rate changes, and other permanent differences | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Federal statutory tax expense | $ | 11,696 | $ | 39,152 | $ | 27,174 | |||||
Increase (decrease) in tax resulting from: | |||||||||||
State tax expense net of federal benefit | 1,106 | 3,834 | 2,753 | ||||||||
Rate change and other | 333 | -306 | 1,377 | ||||||||
Total income tax expense | $ | 13,135 | $ | 42,680 | $ | 31,304 | |||||
Schedule of reconciliation of the Company's effective tax rate to expected federal tax rate | |||||||||||
For the Years Ended | |||||||||||
December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
Expected federal tax rate | 35.00 | % | 35.00 | % | 35.00 | % | |||||
State income taxes | 3.29 | % | 3.43 | % | 3.55 | % | |||||
Change in tax rate | 1.01 | % | -0.28 | % | 1.67 | % | |||||
Effective tax rate | 39.30 | % | 38.15 | % | 40.22 | % | |||||
ASSET_RETIREMENT_OBLIGATIONS_T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
ASSET RETIREMENT OBLIGATIONS | ||||||||
Schedule of change in asset retirement obligations assumed | ||||||||
As of December 31, | ||||||||
2014 | 2013 | |||||||
(in thousands) | ||||||||
Beginning of year | $ | 11,218 | $ | 7,334 | ||||
Additional liabilities incurred | 4,190 | 1,067 | ||||||
Accretion expense | 1,382 | 645 | ||||||
Obligations on properties sold | -833 | — | ||||||
Liabilities settled | -557 | -74 | ||||||
Revisions to estimate | 6,226 | 2,246 | ||||||
End of year | $ | 21,626 | $ | 11,218 | ||||
FAIR_VALUE_MEASUREMENTS_Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
FAIR VALUE MEASUREMENTS | |||||||||||
Schedule of financial assets and liabilities at fair value on recurring basis | |||||||||||
As of December 31, 2014 | |||||||||||
Level 1 | Level 2 | Level 3 | |||||||||
(in thousands) | |||||||||||
Derivative assets | $ | — | $ | 104,005 | $ | — | |||||
Derivative liabilities | $ | — | $ | — | $ | — | |||||
As of December 31, 2013 | |||||||||||
Level 1 | Level 2 | Level 3 | |||||||||
(in thousands) | |||||||||||
Derivative assets | $ | — | $ | 1,151 | $ | — | |||||
Derivative liabilities | $ | — | $ | 6,523 | $ | — | |||||
DERIVATIVES_Tables
DERIVATIVES (Tables) | 0 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||
Feb. 27, 2015 | Dec. 31, 2014 | |||||||||||||||||||||||||||||||||||||||||||||
DERIVATIVES | ||||||||||||||||||||||||||||||||||||||||||||||
Summary of derivative commodity contracts in place | ||||||||||||||||||||||||||||||||||||||||||||||
Total | Average | Average | Fair Market | Total | Average | Average | Fair Market | |||||||||||||||||||||||||||||||||||||||
Volumes | Average | Short Floor | Floor | Average | Value of | Volumes | Average | Short Floor | Floor | Average | Value of | |||||||||||||||||||||||||||||||||||
Derivative | (Bbls/MMBtu | Fixed | Price | Price | Ceiling | Asset | Derivative | (Bbls/MMBtu | Fixed | Price | Price | Ceiling | Asset | |||||||||||||||||||||||||||||||||
Settlement Period | Instrument | per day) | Price | (Short-Put) | (Long-Put) | Price | (Liability) | Settlement Period | Instrument | per day) | Price | (Short-Put) | (Long-Put) | Price | (Liability) | |||||||||||||||||||||||||||||||
Oil | (in thousands) | Oil | (in thousands) | |||||||||||||||||||||||||||||||||||||||||||
1Q 2015 | Swap | 6,000 | $ | 95.39 | $ | 22,363 | 1Q 2015 | Swap | 6,000 | $ | 95.39 | $ | 22,363 | |||||||||||||||||||||||||||||||||
2Q 2015 | Swap | 5,000 | $ | 94.41 | 17,497 | 2Q 2015 | Swap | 5,000 | $ | 94.41 | 17,497 | |||||||||||||||||||||||||||||||||||
3Q 2015 | Swap | 2,000 | $ | 93.43 | 6,534 | 3Q 2015 | Swap | 2,000 | $ | 93.43 | 6,534 | |||||||||||||||||||||||||||||||||||
4Q 2015 | Swap | 2,000 | $ | 93.43 | 6,170 | 4Q 2015 | Swap | 2,000 | $ | 93.43 | 6,170 | |||||||||||||||||||||||||||||||||||
1Q 2015 | 3-Way Collar | 6,500 | $ | 68.08 | $ | 84.32 | $ | 95.90 | 9,264 | 1Q 2015 | 3-Way Collar | 6,500 | $ | 68.08 | $ | 84.32 | $ | 95.90 | 9,264 | |||||||||||||||||||||||||||
2Q 2015 | 3-Way Collar | 5,500 | $ | 67.73 | $ | 84.09 | $ | 95.16 | 7,275 | 2Q 2015 | 3-Way Collar | 5,500 | $ | 67.73 | $ | 84.09 | $ | 95.16 | 7,275 | |||||||||||||||||||||||||||
3Q 2015 | 3-Way Collar | 6,500 | $ | 68.46 | $ | 84.62 | $ | 95.49 | 7,846 | 3Q 2015 | 3-Way Collar | 6,500 | $ | 68.46 | $ | 84.62 | $ | 95.49 | 7,846 | |||||||||||||||||||||||||||
4Q 2015 | 3-Way Collar | 6,500 | $ | 68.46 | $ | 84.62 | $ | 95.49 | 7,091 | 4Q 2015 | 3-Way Collar | 6,500 | $ | 68.46 | $ | 84.62 | $ | 95.49 | 7,091 | |||||||||||||||||||||||||||
2016 | 3-Way Collar | 5,500 | $ | 70.00 | $ | 85.00 | $ | 96.83 | 17,765 | 2016 | 3-Way Collar | 5,500 | $ | 70.00 | $ | 85.00 | $ | 96.83 | 17,765 | |||||||||||||||||||||||||||
$ | 101,805 | $ | 101,805 | |||||||||||||||||||||||||||||||||||||||||||
Gas | Gas | |||||||||||||||||||||||||||||||||||||||||||||
2015 | 3-Way Collar | 15,000 | $ | 3.50 | $ | 4.00 | $ | 4.75 | $ | 2,200 | 2015 | 3-Way Collar | 15,000 | $ | 3.50 | $ | 4.00 | $ | 4.75 | $ | 2,200 | |||||||||||||||||||||||||
$ | 2,200 | $ | 2,200 | |||||||||||||||||||||||||||||||||||||||||||
Total | $ | 104,005 | Total | $ | 104,005 | |||||||||||||||||||||||||||||||||||||||||
Summary of all the Company's derivative positions reported on the accompanying balance sheets | ||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||||||
Balance Sheet Location | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||||||||
Derivative Assets | ||||||||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Current assets | 86,240 | ||||||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Noncurrent assets | 17,765 | ||||||||||||||||||||||||||||||||||||||||||||
Derivative Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Current liabilities | — | ||||||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Long-term liabilities | — | ||||||||||||||||||||||||||||||||||||||||||||
Total net derivative asset | $ | 104,005 | ||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||||||
Balance Sheet Location | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Derivative Assets | (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Current assets | $ | 858 | |||||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Noncurrent assets | 293 | ||||||||||||||||||||||||||||||||||||||||||||
Derivative Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Current liabilities | -5,320 | ||||||||||||||||||||||||||||||||||||||||||||
Commodity contracts | Long-term liabilities | -1,203 | ||||||||||||||||||||||||||||||||||||||||||||
Total net derivative liability | $ | -5,372 | ||||||||||||||||||||||||||||||||||||||||||||
Summary of the components of the derivative gain (loss) presented on the accompanying statements of operations | ||||||||||||||||||||||||||||||||||||||||||||||
For the Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||||||||
Derivative cash settlement gain (loss): | ||||||||||||||||||||||||||||||||||||||||||||||
Oil contracts | $ | 11,523 | $ | -11,755 | $ | -1,492 | ||||||||||||||||||||||||||||||||||||||||
Gas contracts | 715 | 425 | 767 | |||||||||||||||||||||||||||||||||||||||||||
Total derivative cash settlement gain (loss)(1) | $ | 12,238 | $ | -11,330 | $ | -725 | ||||||||||||||||||||||||||||||||||||||||
Change in fair value gain (loss): | $ | 109,377 | $ | -1,142 | $ | 1,649 | ||||||||||||||||||||||||||||||||||||||||
Total derivative gain (loss)(2) | $ | 121,615 | $ | -12,472 | $ | 924 | ||||||||||||||||||||||||||||||||||||||||
-1 | Derivative cash settlement gain (loss) is reported in the derivative cash settlements line item on the accompanying consolidated statements of cash flows within the net cash used in investing activities. | |||||||||||||||||||||||||||||||||||||||||||||
Total derivative gain (loss) is reported in the derivative gain (loss) line item on the accompanying consolidated statements of cash flows within the net cash provided by operating activities. | ||||||||||||||||||||||||||||||||||||||||||||||
EARNINGS_PER_SHARE_Tables
EARNINGS PER SHARE (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
EARNINGS PER SHARE | |||||||||||
Schedule of calculation of earnings per basic and diluted shares from continuing and discontinued operations | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands, except per share data) | |||||||||||
Income from continuing operations: | |||||||||||
Income from continuing operations | $ | 16,982 | $ | 69,582 | $ | 44,571 | |||||
Less: undistributed earnings to unvested restricted stock | 315 | 1,673 | 826 | ||||||||
Undistributed earnings to common shareholders | 16,667 | 67,909 | 43,745 | ||||||||
Basic income per common share from continuing operations | $ | 0.42 | $ | 1.73 | $ | 1.12 | |||||
Diluted income per common share from continuing operations | $ | 0.41 | $ | 1.72 | $ | 1.12 | |||||
Income (loss) from discontinued operations: | |||||||||||
Income (loss) from discontinued operations | $ | 3,301 | $ | -398 | $ | 1,952 | |||||
Less: undistributed earnings (loss) to unvested restricted stock | 62 | -10 | 36 | ||||||||
Undistributed earnings (loss) to common shareholders | 3,239 | -388 | 1,916 | ||||||||
Basic income (loss) per common share from discontinued operations | $ | 0.08 | $ | -0.01 | $ | 0.05 | |||||
Diluted income (loss) per common share from discontinued operations | $ | 0.08 | $ | -0.01 | $ | 0.05 | |||||
Net income: | |||||||||||
Net income | $ | 20,283 | $ | 69,184 | $ | 46,523 | |||||
Less: undistributed earnings to unvested restricted stock | 377 | 1,663 | 862 | ||||||||
Undistributed earnings to common shareholders | 19,906 | 67,521 | 45,661 | ||||||||
Basic net income per common share | $ | 0.50 | $ | 1.72 | $ | 1.17 | |||||
Diluted net income per common share | $ | 0.49 | $ | 1.71 | $ | 1.17 | |||||
Weighted-average shares outstanding—basic | 40,139 | 39,337 | 39,052 | ||||||||
Add: dilutive effect of contingent PSUs | 151 | 66 | — | ||||||||
Weighted-average shares outstanding—diluted | 40,290 | 39,403 | 39,052 | ||||||||
OIL_AND_GAS_ACTIVITIES_Tables
OIL AND GAS ACTIVITIES (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
OIL AND GAS ACTIVITIES | |||||||||||
Schedule of costs incurred in oil and natural gas producing activities | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Acquisition(1) | $ | 228,616 | $ | 13,797 | $ | 58,843 | |||||
Development(2)(3) | 659,633 | 452,455 | 341,135 | ||||||||
Exploration | 5,345 | 2,590 | 4,821 | ||||||||
Total(4) | $ | 893,594 | $ | 468,842 | $ | 404,799 | |||||
-1 | Acquisition costs for unproved properties for the years ended December 31, 2014, 2013 and 2012 were $202.7 million, $3.4 million and $57.0 million, respectively. Acquisition costs for proved properties for the years ended December 31, 2014, 2013 and 2012 were $25.9 million, $10.4 million and $1.8 million, respectively. | ||||||||||
-2 | Development costs include workover costs of $9.8 million, $6.0 million and $4.5 million charged to lease operating expense during the years ended December 31, 2014, 2013 and 2012, respectively. | ||||||||||
-3 | Development costs include gas plant capital expenditures of $0, $4.3 million and $16.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. | ||||||||||
Includes amounts relating to asset retirement obligations of $6.3 million, $2.8 million and $1.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||||
Schedule of net changes in capitalized exploratory well costs | |||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Beginning balance at January 1 | $ | — | $ | — | $ | 5,438 | |||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | — | — | 2,940 | ||||||||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | — | — | — | ||||||||
Capitalized exploratory well costs charged to expense | — | — | -8,378 | ||||||||
Ending balance at December 31 | $ | — | $ | — | $ | — | |||||
DISCLOSURES_ABOUT_OIL_AND_GAS_1
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | |||||||||||
Summary of BCEI's changes in quantities of proved oil, natural gas liquids and natural gas reserves | |||||||||||
Natural | |||||||||||
Oil | Gas | ||||||||||
(MBbl)(1) | (MMcf) | ||||||||||
Balance—December 31, 2011 | 28,216 | 92,982 | |||||||||
Extensions and discoveries(2) | 12,016 | 50,667 | |||||||||
Sales of minerals in place | -669 | — | |||||||||
Production | -2,529 | -5,475 | |||||||||
Purchases of minerals in place | — | — | |||||||||
Revisions to previous estimates(3) | -3,768 | -19,626 | |||||||||
Balance—December 31, 2012 | 33,266 | 118,548 | |||||||||
Extensions and discoveries(2) | 20,123 | 59,936 | |||||||||
Sales of minerals in place | — | — | |||||||||
Production | -4,257 | -9,976 | |||||||||
Purchases of minerals in place | 1,228 | 3,958 | |||||||||
Revisions to previous estimates(3) | -3,878 | -32,852 | |||||||||
Balance—December 31, 2013 | 46,482 | 139,614 | |||||||||
Extensions and discoveries(2) | 13,222 | 41,963 | |||||||||
Sales of minerals in place | -43 | -73 | |||||||||
Production | -6,018 | -14,114 | |||||||||
Purchases of minerals in place | 709 | 1,214 | |||||||||
Revisions to previous estimates(3) | 3,760 | 19,947 | |||||||||
Balance—December 31, 2014 | 58,112 | 188,551 | |||||||||
Proved developed reserves: | |||||||||||
December 31, 2012 | 15,675 | 48,942 | |||||||||
December 31, 2013 | 22,273 | 59,250 | |||||||||
December 31, 2014 | 30,542 | 94,494 | |||||||||
Proved undeveloped reserves: | |||||||||||
December 31, 2012 | 17,591 | 69,606 | |||||||||
December 31, 2013 | 24,209 | 80,364 | |||||||||
December 31, 2014 | 27,570 | 94,057 | |||||||||
-1 | Natural gas liquids reserves are classified with oil reserves. | ||||||||||
-2 | At December 31, 2014, horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 18,980 MBoe, which is 94% of our total additions of 20,216 MBoe. The remainder of the additions came from our Dorcheat Madedonia Field, Mid‑Continent region. | ||||||||||
At December 31, 2013, horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 28,908 MBoe, which is 96% of our total additions of 30,112 MBoe. The remainder of the additions came from our Dorcheat Madedonia and McKamie Patton Fields, Mid‑Continent region. | |||||||||||
At December 31, 2012, horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 17,380 MBoe, which is 85% of our total additions of 20,461 MBoe. The remainder of the additions were the result of vertical drilling during the year in the Wattenberg Field and proved developed non‑producing and proved undeveloped reserve additions in the Dorcheat Macedonia Field, Mid‑Continent region. | |||||||||||
-3 | As of December 31, 2014, we revised our proved reserves upward by 7,333 Mboe, excluding pricing revisions, due primarily to the addition of 49 new proved undeveloped locations on 80-acre spacing, directly offsetting economic proved producing wells drilled prior to 2014, 21 diagonal offsets to economic proved producing wells and 12 proved undeveloped locations greater than one offset to economic proved producing wells but within developed areas and surrounded by proved producing wells. As of December 31, 2014, approximately 70% of our horizontal development in the Wattenberg Field was in the Niobrara B formation. A total of 119 horizontal proved undeveloped locations were added to the proved reserves at December 31, 2014 to either extensions and discoveries or revisions to previous estimates. The positive engineering revision was offset by a small negative performance revision of approximately 540 MBoe. A small negative pricing revision of 248 MBoe resulted from a decrease in average commodity price from $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013 to $94.99 per Bbl WTI and $4.35 per MMBtu HH for the year ended December 31, 2014. | ||||||||||
At December 31, 2013, we revised our proved reserves downward by 9,867 MBoe, excluding pricing revisions, due primarily to the change in focus from vertical to horizontal development in the Watterberg Field. This accounted for 69% of the downward revision and included the elimination of 45 net vertical locations from proved undeveloped, the elimination of all proved non‑ producing reserves associated with vertical well refracs and recompletions, and lower performance from the vertical producers due to increased line pressure. The high line pressure also affected the horizontal reserves creating a negative revision of 1.8 MMBoe, or 18% of the total downward revision. We had a small positive pricing revision of 514 MBoe from an increase in commodity price from $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012 to $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013. | |||||||||||
At December 31, 2012, we revised our proved reserves downward by 6,938 MBoe, excluding pricing revisions, due primarily to a combination of eliminating 50 locations from proved undeveloped reserves as a result of a change in focus from vertical to horizontal development and lower performance than expected from our vertical producers in our Wattenberg Field, Rocky Mountain region. A small negative pricing revision of 101 MBoe resulted from a decrease in commodity price from $96.19 per Bbl WTI and $4.12 per MMBtu HH for the year ended December 31, 2011 to $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012. | |||||||||||
Schedule of standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: | ||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Future cash flows | $ | 5,780,745 | $ | 4,799,149 | $ | 3,367,465 | |||||
Future production costs | -2,257,572 | -1,681,419 | -1,037,537 | ||||||||
Future development costs | -952,041 | -776,512 | -684,160 | ||||||||
Future income tax expense | -457,625 | -576,024 | -298,201 | ||||||||
Future net cash flows | 2,113,507 | 1,765,194 | 1,347,567 | ||||||||
10% annual discount for estimated timing of cash flows | -1,006,131 | -839,911 | -664,126 | ||||||||
Standardized measure of discounted future net cash flows | $ | 1,107,376 | $ | 925,283 | $ | 683,441 | |||||
Schedule of changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: | ||||||||||
For the Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in thousands) | |||||||||||
Beginning of period | $ | 925,283 | $ | 683,441 | $ | 666,186 | |||||
Sale of oil and gas produced, net of production costs | -435,792 | -346,679 | -189,840 | ||||||||
Net changes in prices and production costs | -331,930 | 94,881 | -81,527 | ||||||||
Extensions, discoveries and improved recoveries | 492,144 | 571,384 | 310,595 | ||||||||
Development costs incurred | 116,958 | 67,063 | 161,527 | ||||||||
Changes in estimated development cost | -15,131 | 127,034 | -9,404 | ||||||||
Purchases of mineral in place | 30,919 | 5,442 | — | ||||||||
Sales of mineral in place | -1,173 | — | -14,909 | ||||||||
Revisions of previous quantity estimates | 122,169 | -212,034 | -156,867 | ||||||||
Net change in income taxes | 68,856 | -150,704 | -23,441 | ||||||||
Accretion of discount | 122,722 | 83,468 | 79,398 | ||||||||
Changes in production rates and other | 12,351 | 1,987 | -58,277 | ||||||||
End of period | $ | 1,107,376 | $ | 925,283 | $ | 683,441 | |||||
Schedule of average wellhead prices used in determining future net revenues related to standardized measure calculation | For the Years Ended December 31, | ||||||||||
2014 | 2013 | 2012 | |||||||||
Oil (per Bbl) | $ | 84.28 | $ | 92.03 | $ | 91.04 | |||||
Gas (per Mcf) | $ | 5.24 | $ | 4.67 | $ | 3.78 | |||||
QUARTERLY_FINANCIAL_DATA_UNAUD1
QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
QUARTERLY FINANCIAL DATA (UNAUDITED) | |||||||||||||
Summary of unaudited quarterly financial data | |||||||||||||
Three Months Ended | |||||||||||||
31-Mar | 30-Jun | 30-Sep | 31-Dec | ||||||||||
(in thousands, except per share data) | |||||||||||||
2014 | |||||||||||||
Oil and gas sales(2) | $ | 127,395 | $ | 151,682 | $ | 156,371 | $ | 123,185 | |||||
Operating profit(1)(2) | 58,432 | 63,284 | 59,579 | 25,708 | |||||||||
Net income (loss) | 13,531 | 1,158 | 48,782 | -43,188 | |||||||||
Basic net income (loss) per common share | $ | 0.34 | $ | 0.03 | $ | 1.18 | $ | -1.05 | |||||
Diluted net income (loss) per common share | $ | 0.34 | $ | 0.03 | $ | 1.18 | $ | -1.06 | |||||
2013 | |||||||||||||
Oil and gas sales(2) | $ | 78,307 | $ | 84,517 | $ | 125,973 | $ | 133,063 | |||||
Operating profit(1)(2) | 39,001 | 36,750 | 68,179 | 62,780 | |||||||||
Net income | 11,256 | 14,715 | 17,781 | 25,432 | |||||||||
Basic net income per common share | $ | 0.28 | $ | 0.36 | $ | 0.44 | $ | 0.64 | |||||
Diluted net income per common share | $ | 0.28 | $ | 0.36 | $ | 0.44 | $ | 0.63 | |||||
-1 | Oil and gas sales less lease operating expense, severance and ad valorem taxes, depreciation, and depletion and amortization. | ||||||||||||
Amounts reflect results for continuing operations and exclude results for discontinued operations related to non‑core properties in California sold or held for sale as of December 31, 2014 and 2013. | |||||||||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Minimum | |
Accounts Receivable | |
Period within which crude oil and natural gas receivables are generally collected | 1 month |
Maximum | |
Accounts Receivable | |
Period within which crude oil and natural gas receivables are generally collected | 2 months |
SUMMARY_OF_SIGNIFICANT_ACCOUNT3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 2) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Oil and Gas Producing Activities | |||
Proved oil and gas property impairments | $167,592,000 | $0 | $611,000 |
California assets | Discontinued operations. | |||
Oil and Gas Producing Activities | |||
Proved oil and gas property impairments | 1,600,000 | ||
Non-core Southern Arkansas field | Continuing operations | |||
Oil and Gas Producing Activities | |||
Proved oil and gas property impairments | $611,000 |
SUMMARY_OF_SIGNIFICANT_ACCOUNT4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 3) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||
Oil and gas properties held for sale, net of accumulated depreciation, depletion, and amortization of $- in 2014 and $1,463 in 2013 (note 3) | $360,000 | ||
Revenue Recognition | |||
Minimum period of receipt of revenue | 30 days | ||
Maximum period of receipt of revenue | 90 years | ||
Gas imbalance | 0 | 0 | 0 |
Uncertain Tax Positions | |||
Unrecognized Tax Benefits | $0 | $0 | $0 |
Natural Gas Plant | |||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||
Estimated useful lives | 30 years | ||
Other Property and Equipment | Minimum | |||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||
Estimated useful lives | 3 years | ||
Other Property and Equipment | Maximum | |||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||
Estimated useful lives | 10 years |
SUMMARY_OF_SIGNIFICANT_ACCOUNT5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 4) (Oil and natural gas sales, Customer concentration) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Lion Oil Trading & Transportation, Inc. | |||
Concentrations of Credit Risk | |||
Concentration risk (as a percent) | 19.00% | 23.00% | 32.00% |
Plains Marketing LP | |||
Concentrations of Credit Risk | |||
Concentration risk (as a percent) | 29.00% | 37.00% | 50.00% |
High Sierra Crude Oil & Marketing | |||
Concentrations of Credit Risk | |||
Concentration risk (as a percent) | 11.00% | 15.00% |
ACQUISITIONS_Details
ACQUISITIONS (Details) (USD $) | 0 Months Ended | ||||||
Jul. 31, 2014 | Jul. 08, 2014 | Jul. 31, 2013 | Jul. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Allocation of purchase price: | |||||||
Asset retirement obligation | ($21,626,000) | ($11,218,000) | ($7,334,000) | ||||
Acquired leases in Wattenberg field | |||||||
ACQUISITIONS | |||||||
Area of Land | 5,600 | ||||||
Allocation of purchase price: | |||||||
Net area of acquired properties (in acres) | 5,600 | ||||||
Wattenberg Field Acquisition [Member] | |||||||
ACQUISITIONS | |||||||
Area of Land | -34,000 | ||||||
Annual cash payment | 12,000,000 | 12,000,000 | 12,000,000 | ||||
Purchase price | 223,678,000 | 57,000,000 | |||||
Allocation of purchase price: | |||||||
Proved properties | 25,014,000 | ||||||
Unproved properties | 198,757,000 | ||||||
Asset retirement obligation | -93,000 | ||||||
Purchase price | 223,678,000 | 57,000,000 | |||||
Net area of acquired properties (in acres) | -34,000 | ||||||
Cash paid for acquisition | 174,600,000 | ||||||
Issuance of shares of common stock to acquiree | 853,492 | ||||||
Per share value of shares of common stock sold to acquiree (in dollars per share) | $57.47 | ||||||
Leases | |||||||
2015 | 12,000,000 | ||||||
2016 | 12,000,000 | ||||||
Letter of credit | $24,000,000 |
DISCONTINUED_OPERATIONS_Detail
DISCONTINUED OPERATIONS (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
Jun. 30, 2012 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
DISCONTINUED OPERATIONS | ||||||||||||
Period within which sale of asset takes place to classify it as held for sale | 1 year | |||||||||||
ACQUISTIONS AND DIVESTITURES | ||||||||||||
Proceeds from sale of oil and gas properties | $6,000,000 | $6,700,000 | $9,337,000 | |||||||||
Gain on sale of oil and gas properties | 5,496,000 | 4,192,000 | ||||||||||
Oil and gas properties, successful efforts method: | ||||||||||||
Proved properties | 1,924,380,000 | 1,257,288,000 | 1,924,380,000 | 1,257,288,000 | ||||||||
Unproved properties | 206,721,000 | 45,081,000 | 206,721,000 | 45,081,000 | ||||||||
Wells in progress | 139,208,000 | 110,848,000 | 139,208,000 | 110,848,000 | ||||||||
Less accumulated depreciation, depletion and amortization | -592,073,000 | -224,848,000 | -592,073,000 | -224,848,000 | ||||||||
Net revenues: | ||||||||||||
Oil and gas sales | 123,185,000 | 156,371,000 | 151,682,000 | 127,395,000 | 133,063,000 | 125,973,000 | 84,517,000 | 78,307,000 | 558,633,000 | 421,860,000 | 231,205,000 | |
Operating expenses: | ||||||||||||
Lease operating expense | 72,411,000 | 47,771,000 | 30,695,000 | |||||||||
Severance and ad valorem taxes | 50,430,000 | 27,203,000 | 13,674,000 | |||||||||
Exploration | 5,346,000 | 4,213,000 | 10,715,000 | |||||||||
Depreciation, depletion and amortization | 228,789,000 | 140,176,000 | 66,202,000 | |||||||||
Impairment of oil and gas properties | 167,592,000 | 0 | 611,000 | |||||||||
Total operating expenses | 606,139,000 | 274,865,000 | 153,302,000 | |||||||||
Loss from operations associated with oil and gas properties held for sale | -85,000 | -644,000 | -927,000 | |||||||||
Oil and gas properties in California | ||||||||||||
Oil and gas properties, successful efforts method: | ||||||||||||
Proved properties | 1,721,000 | 1,721,000 | ||||||||||
Unproved properties | 1,000 | 1,000 | ||||||||||
Wells in progress | 101,000 | 101,000 | ||||||||||
Total property and equipment | 1,823,000 | 1,823,000 | ||||||||||
Less accumulated depreciation, depletion and amortization | -1,463,000 | -1,463,000 | ||||||||||
Net property and equipment | 360,000 | 360,000 | ||||||||||
Net revenues: | ||||||||||||
Oil and gas sales | 361,000 | 1,668,000 | 5,410,000 | |||||||||
Operating expenses: | ||||||||||||
Lease operating expense | 366,000 | 1,870,000 | 2,280,000 | |||||||||
Severance and ad valorem taxes | 13,000 | 5,000 | 127,000 | |||||||||
Exploration | 66,000 | 39,000 | ||||||||||
Depreciation, depletion and amortization | 67,000 | 371,000 | 2,243,000 | |||||||||
Impairment of oil and gas properties | 1,648,000 | |||||||||||
Total operating expenses | 446,000 | 2,312,000 | 6,337,000 | |||||||||
Loss from operations associated with oil and gas properties held for sale | ($85,000) | ($644,000) | ($927,000) |
IMPAIRMENTS_Details
IMPAIRMENTS (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Proved oil and gas property impairments | $167,592,000 | $0 | $611,000 |
Impairment of Oil and Gas Properties | 167,592,000 | 2,259,000 | |
Dorcheat Macedonia Field [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Proved oil and gas property impairments | 127,300,000 | ||
McKamie Patton Field [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Proved oil and gas property impairments | 25,000,000 | ||
McCallum Field [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Proved oil and gas property impairments | 15,300,000 | ||
Continuing operations | Non-core Southern Arkansas field | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Proved oil and gas property impairments | 611,000 | ||
Discontinued operations. | California assets | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Proved oil and gas property impairments | $1,600,000 |
OTHER_ASSETS_Details
OTHER ASSETS (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
item | ||
OTHER ASSETS | ||
Number of financial institutions | 3 | |
Certificates of deposit | $228 | $166 |
Restricted cash | 3,000 | |
Deposit for acquisition of oil and gas properties | 1,549 | |
Deferred financing costs | 18,595 | 13,693 |
Total | $23,372 | $13,859 |
ACCOUNTS_PAYABLE_AND_ACCRUED_E2
ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Accounts payable and accrued expenses contain the following: | ||
Drilling and completion costs | $82,844 | $80,971 |
Accounts payable | 5,493 | 3,288 |
Accrued general and administrative cost | 13,541 | 12,720 |
Lease operating expense | 3,569 | 5,440 |
Accrued reclamation cost | 162 | 168 |
Interest | 14,839 | 7,065 |
Accrued oil and gas derivatives | 446 | |
Production and ad valorem taxes and other | 25,340 | 11,567 |
Total accounts payable and accrued expenses | $145,788 | $121,665 |
LONGTERM_DEBT_Details
LONG-TERM DEBT (Details) (USD $) | 12 Months Ended | 0 Months Ended | |||||||
Dec. 31, 2014 | Nov. 15, 2013 | Jul. 15, 2014 | Dec. 31, 2013 | Feb. 24, 2015 | Sep. 30, 2014 | Jul. 31, 2014 | Mar. 29, 2011 | Apr. 09, 2013 | |
item | |||||||||
LONG-TERM DEBT | |||||||||
Long-term debt | $840,619,000 | $508,847,000 | |||||||
Revolver | |||||||||
LONG-TERM DEBT | |||||||||
Maximum borrowing capacity | 1,000,000,000 | ||||||||
Borrowing base | 600,000,000 | ||||||||
Bank commitments | 500,000,000 | ||||||||
Long-term debt | 33,000,000 | 0 | 0 | ||||||
Remaining borrowing capacity | 543,000,000 | 414,000,000 | 576,000,000 | ||||||
Letters of credit outstanding | 24,000,000 | 36,000,000 | 24,000,000 | ||||||
Borrowing base before amendment | 450,000,000 | 525,000,000 | |||||||
Maximum number of additional times for which the entity can redetermined borrowing base | 1 | ||||||||
Borrowing base redetermined based on request by lenders holding aggregate commitments (as a percent) | 66.67% | ||||||||
Revolver | LIBOR | |||||||||
LONG-TERM DEBT | |||||||||
Basis of interest rate | LIBOR | ||||||||
Revolver | Bank Prime Rate | |||||||||
LONG-TERM DEBT | |||||||||
Basis of interest rate | Bank Prime Rate | ||||||||
Revolver | Minimum | |||||||||
LONG-TERM DEBT | |||||||||
Commitment fees (as a percent) | 0.38% | ||||||||
Revolver | Minimum | LIBOR | |||||||||
LONG-TERM DEBT | |||||||||
Interest rate margin (as a percent) | 1.50% | ||||||||
Revolver | Minimum | Bank Prime Rate | |||||||||
LONG-TERM DEBT | |||||||||
Interest rate margin (as a percent) | 0.50% | ||||||||
Revolver | Maximum | |||||||||
LONG-TERM DEBT | |||||||||
Commitment fees (as a percent) | 0.50% | ||||||||
Revolver | Maximum | LIBOR | |||||||||
LONG-TERM DEBT | |||||||||
Interest rate margin (as a percent) | 2.50% | ||||||||
Revolver | Maximum | Bank Prime Rate | |||||||||
LONG-TERM DEBT | |||||||||
Interest rate margin (as a percent) | 1.50% | ||||||||
6.75% Senior Notes | |||||||||
LONG-TERM DEBT | |||||||||
Unamortized premium on 6.75% Senior Notes | 7,619,000 | 8,847,000 | |||||||
Long-term debt | 507,600,000 | 508,800,000 | |||||||
Long term debt - gross | 500,000,000 | 500,000,000 | |||||||
Amount of notes issued | 200,000,000 | 300,000,000 | |||||||
Interest rate (as a percent) | 6.75% | 6.75% | 6.75% | 6.75% | |||||
Net proceeds from sale of notes | 496,800,000 | ||||||||
Expenses and underwriting discounts and commissions | 12,200,000 | ||||||||
Ownership percentage in all existing subsidiaries | 100.00% | ||||||||
Amount of independent assets other than ownership interest in subsidiaries and affiliates | 0 | ||||||||
Amount of independent operations other than ownership interest in subsidiaries and affiliates | 0 | ||||||||
6.75% Senior Notes | Prior to August 1, 2016 | |||||||||
LONG-TERM DEBT | |||||||||
Redemption price as a percentage of principal amount of notes plus accrued and unpaid interest | 106.75% | ||||||||
6.75% Senior Notes | Prior to April 15, 2017 | |||||||||
LONG-TERM DEBT | |||||||||
Percentage of principal amount redeemed | 100.00% | ||||||||
6.75% Senior Notes | 2017 | |||||||||
LONG-TERM DEBT | |||||||||
Percentage of principal amount redeemed | 103.38% | ||||||||
6.75% Senior Notes | 2018 | |||||||||
LONG-TERM DEBT | |||||||||
Percentage of principal amount redeemed | 101.69% | ||||||||
6.75% Senior Notes | 2019 and thereafter | |||||||||
LONG-TERM DEBT | |||||||||
Percentage of principal amount redeemed | 100.00% | ||||||||
6.75% Senior Notes | Maximum | Prior to August 1, 2016 | |||||||||
LONG-TERM DEBT | |||||||||
Percentage of principal amount redeemed | 35.00% | ||||||||
5.75% Senior Notes | |||||||||
LONG-TERM DEBT | |||||||||
Long-term debt | 300,000,000 | ||||||||
Amount of notes issued | 300,000,000 | ||||||||
Interest rate (as a percent) | 5.75% | 5.75% | 5.75% | ||||||
Net proceeds from sale of notes | 293,400,000 | ||||||||
Expenses and underwriting discounts and commissions | $6,600,000 | ||||||||
5.75% Senior Notes | Prior to April 15, 2017 | |||||||||
LONG-TERM DEBT | |||||||||
Redemption price as a percentage of principal amount of notes plus accrued and unpaid interest | 105.75% | ||||||||
5.75% Senior Notes | 2018 | |||||||||
LONG-TERM DEBT | |||||||||
Percentage of principal amount redeemed | 102.88% | ||||||||
5.75% Senior Notes | 2019 | |||||||||
LONG-TERM DEBT | |||||||||
Percentage of principal amount redeemed | 101.44% | ||||||||
5.75% Senior Notes | 2020 and thereafter | |||||||||
LONG-TERM DEBT | |||||||||
Percentage of principal amount redeemed | 100.00% | ||||||||
5.75% Senior Notes | Maximum | Prior to April 15, 2017 | |||||||||
LONG-TERM DEBT | |||||||||
Percentage of principal amount redeemed | 35.00% |
COMMITMENTS_AND_CONTINGENT_LIA2
COMMITMENTS AND CONTINGENT LIABILITIES (Details) (USD $) | 0 Months Ended | 9 Months Ended | 12 Months Ended | 1 Months Ended | ||
Oct. 01, 2014 | Sep. 30, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 31, 2014 | |
claim | ||||||
Commitments | ||||||
Number of Claims | 0 | |||||
Total commitment | $540,000,000 | |||||
Office Leases | ||||||
Leases | ||||||
2015 | 38,441,000 | |||||
2016 | 68,878,000 | |||||
2017 | 91,916,000 | |||||
2018 | 91,990,000 | |||||
2019 | 92,056,000 | |||||
2020 and thereafter | 170,132,000 | |||||
Total | 553,413,000 | |||||
Rent expense | $2,000,000 | $1,400,000 | $886,000 | |||
Commitment one | ||||||
Commitments | ||||||
Minimum commitment of crude oil | 12,580 | |||||
Term of commitment period | 5 years | |||||
Commitment two | ||||||
Commitments | ||||||
Minimum commitment of crude oil | 15,000 | |||||
Term of commitment period | 7 years |
STOCKBASED_COMPENSATION_Detail
STOCK-BASED COMPENSATION (Details) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | |||
Dec. 23, 2010 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Feb. 11, 2013 | Feb. 05, 2013 | |
STOCK-BASED COMPENSATION | ||||||
Vesting period | 3 years | 3 years | ||||
Weighted-Average Grant-Date Fair Value | ||||||
Excess income tax benefit from the vesting of stock awards | $128,000 | |||||
PSUs | ||||||
Weighted-Average Grant-Date Fair Value | ||||||
Ratio at which award holders get common stock of the company | 1.33 | |||||
Percentage of awards earned during performance cycle | 200.00% | |||||
PSUs | Maximum | ||||||
Weighted-Average Grant-Date Fair Value | ||||||
Ratio at which award holders get common stock of the company | 0.6667 | |||||
RSU | ||||||
Weighted-Average Grant-Date Fair Value | ||||||
Excess income tax benefit from the vesting of stock awards | 0 | 127,830 | 0 | |||
2011 Long Term Incentive Plan | Restricted shares | ||||||
STOCK-BASED COMPENSATION | ||||||
Ratio of restricted stock to common stock to be released from restrictions upon completion of the vesting period | 1 | |||||
Vesting portion of shares | 0.3333 | |||||
Vesting period | 3 years | |||||
Restricted Stock | ||||||
Non-vested at beginning of year (in shares) | 836,002 | 929,336 | 437,787 | |||
Granted (in shares) | 309,949 | 310,439 | 731,034 | |||
Vested (in shares) | -524,818 | -371,956 | -159,147 | |||
Forfeited (in shares) | -31,604 | -31,817 | -80,338 | |||
Non-vested at end of year (in shares) | 589,529 | 836,002 | 929,336 | |||
Weighted-Average Grant-Date Fair Value | ||||||
Non-vested at beginning of year (in dollars per share) | 25.11 | $17.06 | $17 | |||
Granted (in dollars per share) | 45.87 | $39.89 | $16.98 | |||
Vested (in dollars per share) | 25.95 | $17.44 | $17.11 | |||
Forfeited (in dollars per share) | 32.73 | $24.09 | $15.89 | |||
Non-vested at end of year (in dollars per share) | 37.66 | $25.11 | $17.06 | |||
Shares granted | 309,949 | 310,439 | 731,034 | |||
2011 Long Term Incentive Plan | 2013 LTIP grants | Employees | ||||||
STOCK-BASED COMPENSATION | ||||||
Fair value of shares granted | 13,900,000 | 12,400,000 | 11,800,000 | |||
Stock-based compensation expense | 13,900,000 | 6,900,000 | 1,700,000 | |||
Unrecognized compensation cost | 15,600,000 | |||||
Restricted Stock | ||||||
Granted (in shares) | 297,030 | 292,396 | 697,500 | |||
Weighted-Average Grant-Date Fair Value | ||||||
Shares granted | 297,030 | 292,396 | 697,500 | |||
2011 Long Term Incentive Plan | 2013 LTIP grants | Non-employee directors | ||||||
STOCK-BASED COMPENSATION | ||||||
Vesting period | 1 year | |||||
Stock-based compensation expense | 734,000 | 445,000 | 267,000 | |||
Restricted Stock | ||||||
Granted (in shares) | 12,919 | 18,043 | 33,534 | |||
Weighted-Average Grant-Date Fair Value | ||||||
Shares granted | 12,919 | 18,043 | 33,534 | |||
2011 Long Term Incentive Plan | PSUs | ||||||
Restricted Stock | ||||||
Non-vested at beginning of year (in shares) | 40,191 | |||||
Granted (in shares) | 82,312 | 41,622 | ||||
Vested (in shares) | -28,330 | |||||
Forfeited (in shares) | -1,431 | |||||
Non-vested at end of year (in shares) | 94,173 | 40,191 | ||||
Weighted-Average Grant-Date Fair Value | ||||||
Non-vested at beginning of year (in dollars per share) | 32.05 | |||||
Granted (in dollars per share) | 41.94 | $32.01 | ||||
Vested (in dollars per share) | 42.5 | |||||
Forfeited (in dollars per share) | $30.85 | |||||
Non-vested at end of year (in dollars per share) | 37.55 | $32.05 | ||||
Shares granted | 82,312 | 41,622 | ||||
2011 Long Term Incentive Plan | PSUs | Officers | ||||||
STOCK-BASED COMPENSATION | ||||||
Fair value of shares granted | 3,500,000 | 1,200,000 | ||||
Stock-based compensation expense | 1,300,000 | 340,000 | ||||
Unrecognized compensation cost | 3,100,000 | |||||
Restricted Stock | ||||||
Granted (in shares) | 82,312 | 41,622 | ||||
Weighted-Average Grant-Date Fair Value | ||||||
Measurement period | 3 years | |||||
Shares granted | 82,312 | 41,622 | ||||
2011 Long Term Incentive Plan | PSUs | Officers | Minimum | ||||||
Weighted-Average Grant-Date Fair Value | ||||||
Ratio at which award holders get common stock of the company | 0 | |||||
2011 Long Term Incentive Plan | PSUs | Officers | Maximum | ||||||
Weighted-Average Grant-Date Fair Value | ||||||
Ratio at which award holders get common stock of the company | 2 | |||||
Plan | Class B | ||||||
Weighted-Average Grant-Date Fair Value | ||||||
Shares available under the plan | 10,000 | |||||
Plan | Restricted shares | ||||||
STOCK-BASED COMPENSATION | ||||||
Stock-based compensation expense | 4,800,000 | 2,500,000 | 2,500,000 | |||
Unrecognized compensation cost | 0 | |||||
Restricted Stock | ||||||
Granted (in shares) | 437,787 | |||||
Weighted-Average Grant-Date Fair Value | ||||||
IPO stated price (in dollars per share) | 17 | |||||
Shares granted | 437,787 | |||||
BCEC Management Incentive Plan | ||||||
STOCK-BASED COMPENSATION | ||||||
Stock-based compensation expense | $2,500,000 | |||||
BCEC Management Incentive Plan | Employees | ||||||
Weighted-Average Grant-Date Fair Value | ||||||
Number of shares of common stock distributed that were fully vested and held by the BCEC Investment Trust | 59,372 | |||||
Grant date fair market value (in dollars per share) | $34.89 | |||||
BCEC Management Incentive Plan | Former employees | ||||||
Weighted-Average Grant-Date Fair Value | ||||||
Number of shares of common stock distributed that were fully vested and held by the BCEC Investment Trust | 13,825 | |||||
Grant date fair market value (in dollars per share) | $34.18 |
STOCKBASED_COMPENSATION_Detail1
STOCK-BASED COMPENSATION (Details 2) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
STOCK-BASED COMPENSATION | |||
Amount of employer's contribution | $1,400,000 | $837,000 | $589,000 |
INCOME_TAXES_Details
INCOME TAXES (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Reconciliation of effective tax rate to expected federal tax rate | |||
Expected federal tax rate (as a percent) | 35.00% | 35.00% | 35.00% |
State income taxes (as a percent) | 3.29% | 3.43% | 3.55% |
Change in tax rate (as a percent) | 1.01% | -0.28% | 1.67% |
Effective tax rate (as a percent) | 39.30% | 38.15% | 40.22% |
Current tax expense | |||
Federal | $165,000 | $122,000 | $289,000 |
State | -16,000 | 126,000 | 243,000 |
Deferred tax expense | 12,986,000 | 42,432,000 | 30,772,000 |
Total income tax expense | 13,135,000 | 42,680,000 | 31,304,000 |
Deferred tax liabilities: | |||
Oil and gas properties | 201,635,000 | 195,776,000 | |
Derivative liability | 40,060,000 | ||
Total deferred tax liabilities | 241,695,000 | 195,776,000 | |
Deferred tax assets: | |||
Federal and state tax net operating loss carryforward | 59,952,000 | 31,289,000 | |
Reclamation costs | 8,344,000 | 4,311,000 | |
Stock compensation | 3,845,000 | 2,617,000 | |
Derivative liability | 1,833,000 | ||
AMT credit | 812,000 | 776,000 | |
State bonus depreciation addback | 2,083,000 | 1,938,000 | |
Other long-term liabilities | 992,000 | 331,000 | |
Total deferred tax assets | 76,028,000 | 43,095,000 | |
Total non-current net deferred tax liability | 165,667,000 | 152,681,000 | |
Reconciliation statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, rate changes, and other permanent differences | |||
Federal statutory tax expense | 11,696,000 | 39,152,000 | 27,174,000 |
Increase (decrease) in tax resulting from: | |||
State tax expense net of federal benefit | 1,106,000 | 3,834,000 | 2,753,000 |
Rate change and other | 333,000 | -306,000 | 1,377,000 |
Total income tax expense | 13,135,000 | 42,680,000 | 31,304,000 |
Net operating loss carryforwards | |||
Net operating loss carryovers for federal income tax purposes | 177,300,000 | 95,100,000 | |
Net operating loss carryovers for federal income tax purposes, not benefited for financial statement purposes | 14,500,000 | 9,300,000 | |
Deferred income tax expense due to change in the effective tax rate | 400,000 | ||
Estimated effective tax rate after revision (as a percent) | 35.00% | ||
Deferred income tax expense due to revision of estimated effective tax rate | 1,200,000 | ||
Additional federal income tax expense | 29,600,000 | ||
Unrecognized tax benefits | $0 | $0 | $0 |
ASSET_RETIREMENT_OBLIGATIONS_D
ASSET RETIREMENT OBLIGATIONS (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Change in asset retirement obligations | ||
Beginning of year | $11,218,000 | $7,334,000 |
Additional liabilities incurred | 4,190,000 | 1,067,000 |
Accretion expense | 1,382,000 | 645,000 |
Obligations on properties sold | -833,000 | |
Liabilities settled | -557,000 | -74,000 |
Revisions to estimate | 6,226,000 | 2,246,000 |
End of year | 21,626,000 | 11,218,000 |
Asset retirement obligations | $162,000 | $168,000 |
Maximum | ||
Asset retirement obligation liability line items | ||
Discount rate (as a percent) | 11.70% | |
Minimum | ||
Asset retirement obligation liability line items | ||
Discount rate (as a percent) | 8.00% |
FAIR_VALUE_MEASUREMENTS_Detail
FAIR VALUE MEASUREMENTS (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
item | ||
Financial assets and liabilities accounted for at fair value | ||
Volatility rate per Bbl or MMBtu in the NYMEX forward curve (as a percent) | 10.00% | |
Total number of counterparties in derivative financial instruments | 5 | |
Oil | Forecast | ||
Financial assets and liabilities accounted for at fair value | ||
Change in derivative gain (loss) | -17,200,000 | |
Natural gas | Forecast | ||
Financial assets and liabilities accounted for at fair value | ||
Change in derivative gain (loss) | 15,300,000 | |
Level 2 | ||
Financial assets and liabilities accounted for at fair value | ||
Derivative assets | 1,151,000 | |
Derivative liabilities | 6,523,000 | |
Recurring | Level 2 | ||
Financial assets and liabilities accounted for at fair value | ||
Derivative assets | 104,005,000 |
FAIR_VALUE_MEASUREMENTS_Detail1
FAIR VALUE MEASUREMENTS (Details 2) (USD $) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 15, 2013 | Apr. 09, 2013 | Jul. 15, 2014 | |
Derivatives measured at fair value | ||||||
Proved oil and gas property impairments | $167,592,000 | $0 | $611,000 | |||
Proved properties | 1,924,380,000 | 1,257,288,000 | ||||
Unproved properties | 206,721,000 | 45,081,000 | ||||
Asset retirement obligations | 21,464,000 | 11,050,000 | ||||
Long-term debt | 840,619,000 | 508,847,000 | ||||
Dorcheat Macedonia Field [Member] | ||||||
Derivatives measured at fair value | ||||||
Proved oil and gas property impairments | 127,300,000 | |||||
Proved properties | 519,200,000 | |||||
McKamie Patton Field [Member] | ||||||
Derivatives measured at fair value | ||||||
Proved oil and gas property impairments | 25,000,000 | |||||
Proved properties | 41,000,000 | |||||
McCallum Field [Member] | ||||||
Derivatives measured at fair value | ||||||
Proved oil and gas property impairments | 15,300,000 | |||||
Proved properties | 15,300,000 | |||||
6.75% Senior Notes | ||||||
Derivatives measured at fair value | ||||||
Outstanding amount | 500,000,000 | |||||
Long-term debt | 507,600,000 | 508,800,000 | ||||
Interest rate (as a percent) | 6.75% | 6.75% | 6.75% | 6.75% | ||
5.75% Senior Notes | ||||||
Derivatives measured at fair value | ||||||
Outstanding amount | 300,000,000 | |||||
Long-term debt | 300,000,000 | |||||
Interest rate (as a percent) | 5.75% | 5.75% | 5.75% | |||
Fair value of senior notes | 243,000,000 | |||||
Fair Value | ||||||
Derivatives measured at fair value | ||||||
Proved properties | 0 | |||||
Unproved properties | 0 | |||||
Asset retirement obligations | 6,200,000 | 0 | ||||
Fair value of senior notes | 440,000,000 | 527,500,000 | ||||
Fair Value | Dorcheat Macedonia Field [Member] | ||||||
Derivatives measured at fair value | ||||||
Proved properties | 391,900,000 | |||||
Fair Value | McKamie Patton Field [Member] | ||||||
Derivatives measured at fair value | ||||||
Proved properties | 16,000,000 | |||||
Fair Value | McCallum Field [Member] | ||||||
Derivatives measured at fair value | ||||||
Proved properties | $0 |
DERIVATIVES_Details
DERIVATIVES (Details) (Commodity derivative, USD $) | Feb. 27, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |||
Derivative contract | |||
Fair Value of Asset (Liability) | $104,005 | $104,005 | ($5,372) |
Oil | |||
Derivative contract | |||
Fair Value of Asset (Liability) | 101,805 | 101,805 | |
Natural gas | |||
Derivative contract | |||
Fair Value of Asset (Liability) | 2,200 | 2,200 | |
Swap | Oil | 1Q 2015 | |||
Derivative contract | |||
Total Volumes (in units per day) | 6,000 | 6,000 | |
Average Fixed Price | 95.39 | 95.39 | |
Fair Value of Asset (Liability) | 22,363 | 22,363 | |
Swap | Oil | 2Q 2015 | |||
Derivative contract | |||
Total Volumes (in units per day) | 5,000 | 5,000 | |
Average Fixed Price | 94.41 | 94.41 | |
Fair Value of Asset (Liability) | 17,497 | 17,497 | |
Swap | Oil | 3Q 2015 | |||
Derivative contract | |||
Total Volumes (in units per day) | 2,000 | 2,000 | |
Average Fixed Price | 93.43 | 93.43 | |
Fair Value of Asset (Liability) | 6,534 | 6,534 | |
Swap | Oil | 4Q 2015 | |||
Derivative contract | |||
Total Volumes (in units per day) | 2,000 | 2,000 | |
Average Fixed Price | 93.43 | 93.43 | |
Fair Value of Asset (Liability) | 6,170 | 6,170 | |
3-Way Collar | Oil | 1Q 2015 | |||
Derivative contract | |||
Total Volumes (in units per day) | 6,500 | 6,500 | |
Average Short Floor Price | 68.08 | 68.08 | |
Average Floor Price | 84.32 | 84.32 | |
Average Ceiling Price | 95.9 | 95.9 | |
Fair Value of Asset (Liability) | 9,264 | 9,264 | |
3-Way Collar | Oil | 2Q 2015 | |||
Derivative contract | |||
Total Volumes (in units per day) | 5,500 | 5,500 | |
Average Short Floor Price | 67.73 | 67.73 | |
Average Floor Price | 84.09 | 84.09 | |
Average Ceiling Price | 95.16 | 95.16 | |
Fair Value of Asset (Liability) | 7,275 | 7,275 | |
3-Way Collar | Oil | 3Q 2015 | |||
Derivative contract | |||
Total Volumes (in units per day) | 6,500 | 6,500 | |
Average Short Floor Price | 68.46 | 68.46 | |
Average Floor Price | 84.62 | 84.62 | |
Average Ceiling Price | 95.49 | 95.49 | |
Fair Value of Asset (Liability) | 7,846 | 7,846 | |
3-Way Collar | Oil | 4Q 2015 | |||
Derivative contract | |||
Total Volumes (in units per day) | 6,500 | 6,500 | |
Average Short Floor Price | 68.46 | 68.46 | |
Average Floor Price | 84.62 | 84.62 | |
Average Ceiling Price | 95.49 | 95.49 | |
Fair Value of Asset (Liability) | 7,091 | 7,091 | |
3-Way Collar | Oil | 2016 | |||
Derivative contract | |||
Total Volumes (in units per day) | 5,500 | 5,500 | |
Average Short Floor Price | 70 | 70 | |
Average Floor Price | 85 | 85 | |
Average Ceiling Price | 96.83 | 96.83 | |
Fair Value of Asset (Liability) | 17,765 | 17,765 | |
3-Way Collar | Natural gas | 1Q 2015 | |||
Derivative contract | |||
Total Volumes (in units per day) | 15,000 | 15,000 | |
Average Short Floor Price | 3.5 | 3.5 | |
Average Floor Price | 4 | 4 | |
Average Ceiling Price | 4.75 | 4.75 | |
Fair Value of Asset (Liability) | $2,200 | $2,200 |
DERIVATIVES_Details_2
DERIVATIVES (Details 2) (Commodity derivative, USD $) | Feb. 27, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |||
Derivatives measured at fair value | |||
Total net derivative liability | $104,005 | $104,005 | ($5,372) |
Current assets | |||
Derivatives measured at fair value | |||
Derivative Assets | 86,240 | 858 | |
Noncurrent assets | |||
Derivatives measured at fair value | |||
Derivative Assets | 17,765 | 293 | |
Current liabilities | |||
Derivatives measured at fair value | |||
Derivative Liabilities | -5,320 | ||
Long-term liabilities | |||
Derivatives measured at fair value | |||
Derivative Liabilities | ($1,203) |
DERIVATIVES_Details_3
DERIVATIVES (Details 3) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Components of the derivative gain (loss) | |||
Derivative gain (loss) | $121,615 | ($12,472) | $924 |
Commodity derivative | |||
Components of the derivative gain (loss) | |||
Derivative cash settlement gain (loss) | 12,238 | -11,330 | -725 |
Change in fair value gain (loss) | 109,377 | -1,142 | 1,649 |
Derivative gain (loss) | 121,615 | -12,472 | 924 |
Commodity derivative | Oil | |||
Components of the derivative gain (loss) | |||
Derivative cash settlement gain (loss) | 11,523 | -11,755 | -1,492 |
Commodity derivative | Natural gas | |||
Components of the derivative gain (loss) | |||
Derivative cash settlement gain (loss) | $715 | $425 | $767 |
EARNINGS_PER_SHARE_Details
EARNINGS PER SHARE (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income from continuing operations: | |||||||||||
Income from continuing operations | $16,982 | $69,582 | $44,571 | ||||||||
Less: undistributed earnings to unvested restricted stock | 315 | 1,673 | 826 | ||||||||
Undistributed earnings to common shareholders | 16,667 | 67,909 | 43,745 | ||||||||
Basic income per common share from continuing operations (in dollars per share) | $0.42 | $1.73 | $1.12 | ||||||||
Diluted income per common share from continuing operations (in dollars per share) | $0.41 | $1.72 | $1.12 | ||||||||
Income (loss) from discontinued operations: | |||||||||||
Income (loss) from discontinued operations | 3,301 | -398 | 1,952 | ||||||||
Less: undistributed earnings to unvested restricted stock | 62 | -10 | 36 | ||||||||
Undistributed earnings (loss) to common shareholders | 3,239 | -388 | 1,916 | ||||||||
Basic loss per common share from discontinued operations (in dollars per share) | $0.08 | ($0.01) | $0.05 | ||||||||
Diluted loss per common share from discontinued operations (in dollars per share) | $0.08 | ($0.01) | $0.05 | ||||||||
Net income: | |||||||||||
Net Income | -43,188 | 48,782 | 1,158 | 13,531 | 25,432 | 17,781 | 14,715 | 11,256 | 20,283 | 69,184 | 46,523 |
Less: undistributed earnings to unvested restricted stock | 377 | 1,663 | 862 | ||||||||
Undistributed earnings to common shareholders | $19,906 | $67,521 | $45,661 | ||||||||
Basic net income per common share (in dollars per share) | ($1.05) | $1.18 | $0.03 | $0.34 | $0.64 | $0.44 | $0.36 | $0.28 | $0.50 | $1.72 | $1.17 |
Diluted net income per common share (in dollars per share) | ($1.06) | $1.18 | $0.03 | $0.34 | $0.63 | $0.44 | $0.36 | $0.28 | $0.49 | $1.71 | $1.17 |
Weighted-average shares outstanding - basic | 40,139 | 39,337 | 39,052 | ||||||||
Add: dilutive effect of contingent PSUs | 151 | 66 | |||||||||
Weighted-average shares outstanding - diluted | 40,290 | 39,403 | 39,052 | ||||||||
Antidilutive shares | 0 | 0 | 0 |
SUBSEQUENT_EVENTS_Details
SUBSEQUENT EVENTS: (Details) (USD $) | 12 Months Ended | 0 Months Ended |
Dec. 31, 2012 | Feb. 06, 2015 | |
Equity [Abstract] | ||
Underwriter discounts, commissions and offering expenses | $3,000 | |
Subsequent event | ||
Equity [Abstract] | ||
Shares of common stock sold in public offering | 8,050,000 | |
Net proceeds | 202,600,000 | |
Underwriter discounts, commissions and offering expenses | $6,700,000 |
OIL_AND_GAS_ACTIVITIES_Details
OIL AND GAS ACTIVITIES (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
item | item | ||
Costs incurred in oil and natural gas producing activities | |||
Acquisition | $228,616,000 | $13,797,000 | $58,843,000 |
Development | 659,633,000 | 452,455,000 | 341,135,000 |
Exploration | 5,345,000 | 2,590,000 | 4,821,000 |
Total | 893,594,000 | 468,842,000 | 404,799,000 |
Acquisition costs for unproved properties | 202,700,000 | 3,400,000 | 57,000,000 |
Proved property acquisitions | 25,900,000 | 10,400,000 | 1,800,000 |
Workover costs charged to lease operating expense | 9,800,000 | 6,000,000 | 4,500,000 |
Gas plant capital expenditures | 0 | 4,300,000 | 16,200,000 |
ARO included in total cost incurred | 6,300,000 | 2,800,000 | 1,100,000 |
Net changes in capitalized exploratory well costs | |||
Balance at the beginning of the period | 5,438,000 | ||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 2,940,000 | ||
Capitalized exploratory well costs charged to expense | -8,378,000 | ||
Number of exploratory wells for which drilling was commenced and deemed as dry | 1 | 1 | |
Capitalized cost for exploratory wells in progress for a period of greater than one year | $1,043,000 | $629,886 | $8,378,612 |
DISCLOSURES_ABOUT_OIL_AND_GAS_2
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Revisions to previous estimates | 7,333 | 6,938 | ||
Extensions and discoveries | 20,216 | 30,112 | 20,461 | |
Revisions to previous estimates for pricing | 514 | |||
Revisions to previous estimates | -9,867 | |||
Increase (decrease) in proved undeveloped locations | 49 | -50 | ||
Area of spacing on which new proved undeveloped locations are added | 80 | |||
Number of diagonal offsets to economic proved producing wells | 21 | |||
Increase in proved undeveloped locations offsetting economic proved producing wells | 12 | |||
Minimum number of offset to economic proved producing wells | 1 | |||
Downward revision in vertical reserves (as a percent) | 69.00% | |||
Number of locations that were moved from unproved to proved undeveloped | -45 | |||
Revisions to previous estimates due to high pressure line | -1.8 | |||
Downward revision in horizontal reserves (as a percent) | 18.00% | |||
Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Extensions and discoveries | 18,980 | 28,908 | 17,380 | |
Revisions to previous estimates for pricing | -248 | -101 | ||
Revisions to previous estimates for performance | $540 | |||
Extensions and discoveries (as a percent) | 94.00% | 96.00% | 85.00% | |
Increase (decrease) in proved undeveloped locations | 119 | |||
Percentage of horizontal development in the Niobrara B formation | 70.00% | |||
Oil | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Balance at the beginning of the period | 46,482,000 | 33,266,000 | 28,216,000 | |
Extensions and discoveries | 13,222,000 | 20,123,000 | 12,016,000 | |
Sales of mineral in place | -43,000 | -669,000 | ||
Purchases of minerals in place | 709,000 | 1,228,000 | ||
Production | -6,018,000 | -4,257,000 | -2,529,000 | |
Revisions to previous estimates | 3,760,000 | -3,878,000 | -3,768,000 | |
Balance at the end of the period | 58,112,000 | 46,482,000 | 33,266,000 | |
Proved developed reserves: | 30,542,000 | 22,273,000 | 15,675,000 | |
Proved undeveloped reserves: | 27,570,000 | 24,209,000 | 17,591,000 | |
Oil and gas commodity price (in dollars per Bbl/ MMBtu) | 96.91 | 94.71 | ||
Oil | Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Oil and gas commodity price (in dollars per Bbl/ MMBtu) | 94.99 | 96.91 | 94.71 | 96.19 |
Natural gas | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Balance at the beginning of the period | 139,614 | 118,548 | 92,982 | |
Extensions and discoveries | 41,963 | 59,936 | 50,667 | |
Sales of mineral in place | -73 | |||
Purchases of minerals in place | 1,214 | 3,958 | ||
Production | -14,114 | -9,976 | -5,475 | |
Revisions to previous estimates | 19,947 | -32,852 | -19,626 | |
Balance at the end of the period | 188,551 | 139,614 | 118,548 | |
Proved developed reserves: | 94,494 | 59,250 | 48,942 | |
Proved undeveloped reserves: | 94,057 | 80,364 | 69,606 | |
Oil and gas commodity price (in dollars per Bbl/ MMBtu) | 3.67 | 2.76 | ||
Natural gas | Wattenberg Field, Rocky Mountain Region | ||||
Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
Oil and gas commodity price (in dollars per Bbl/ MMBtu) | 4.35 | 3.67 | 2.76 | 4.12 |
DISCLOSURES_ABOUT_OIL_AND_GAS_3
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 2) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | |||
Future cash flows | $5,780,745 | $4,799,149 | $3,367,465 |
Future production costs | 2,257,572 | 1,681,419 | 1,037,537 |
Future development costs | 952,041 | 776,512 | 684,160 |
Future income tax expense | 457,625 | 576,024 | 298,201 |
Future net cash flows | 2,113,507 | 1,765,194 | 1,347,567 |
10% annual discount for estimated timing of cash flows | -1,006,131 | -839,911 | -664,126 |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total | 1,107,376 | 925,283 | 683,441 |
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | |||
Beginning of period | 925,283 | 683,441 | 666,186 |
Sale of oil and gas produced, net of production costs | -435,792 | -346,679 | -189,840 |
Net changes in prices and production costs | -331,930 | 94,881 | -81,527 |
Extensions, discoveries and improved recoveries | 492,144 | 571,384 | 310,595 |
Development costs incurred | 116,958 | 67,063 | 161,527 |
Changes in estimated development cost | -15,131 | 127,034 | -9,404 |
Purchases of mineral in place | 30,919 | 5,442 | |
Sales of mineral in place | -1,173 | -14,909 | |
Revisions of previous quantity estimates | 122,169 | -212,034 | -156,867 |
Net change in income taxes | 68,856 | -150,704 | -23,441 |
Accretion of discount | 122,722 | 83,468 | 79,398 |
Changes in production rates and other | 12,351 | 1,987 | -58,277 |
End of period | $1,107,376 | $925,283 | $683,441 |
DISCLOSURES_ABOUT_OIL_AND_GAS_4
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 3) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Oil | |||
Average wellhead prices | |||
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | 84.28 | 92.03 | 91.04 |
Natural gas | |||
Average wellhead prices | |||
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | 5.24 | 4.67 | 3.78 |
QUARTERLY_FINANCIAL_DATA_UNAUD2
QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
QUARTERLY FINANCIAL DATA (UNAUDITED) | |||||||||||
Oil and gas sales | $123,185 | $156,371 | $151,682 | $127,395 | $133,063 | $125,973 | $84,517 | $78,307 | $558,633 | $421,860 | $231,205 |
Operating profit | 25,708 | 59,579 | 63,284 | 58,432 | 62,780 | 68,179 | 36,750 | 39,001 | -47,506 | 146,995 | 77,903 |
Net income | ($43,188) | $48,782 | $1,158 | $13,531 | $25,432 | $17,781 | $14,715 | $11,256 | $20,283 | $69,184 | $46,523 |
Basic net income per common share (in dollars per share) | ($1.05) | $1.18 | $0.03 | $0.34 | $0.64 | $0.44 | $0.36 | $0.28 | $0.50 | $1.72 | $1.17 |
Diluted net income per common share (in dollars per share) | ($1.06) | $1.18 | $0.03 | $0.34 | $0.63 | $0.44 | $0.36 | $0.28 | $0.49 | $1.71 | $1.17 |
Uncategorized_Items
Uncategorized Items | 1/1/2013 - 3/31/2013 | |
USD ($) | ||
[us-gaap_CommonStockSharesIssued] | 39,477,584 | |
[us-gaap_GainLossOnSaleOfOilAndGasProperty] | 5,500,000 |