Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 28, 2017 | Jun. 30, 2016 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | NORTHERN OIL & GAS, INC. | ||
Entity Central Index Key | 1,104,485 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $ 208.7 | ||
Entity Common Stock, Shares Outstanding | 63,251,197 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 |
BALANCE SHEETS
BALANCE SHEETS - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Current Assets: | ||
Cash and Cash Equivalents | $ 6,486,098 | $ 3,390,389 |
Accounts Receivable, Net | 35,840,042 | 51,445,026 |
Advances to Operators | 1,577,204 | 1,689,879 |
Prepaid and Other Expenses | 1,584,129 | 892,867 |
Derivative Instruments | 4,517 | 64,611,558 |
Income Tax Receivable | 1,402,179 | 0 |
Total Current Assets | 46,894,169 | 122,029,719 |
Oil and Natural Gas Properties, Full Cost Method of Accounting | ||
Proved | 2,428,595,048 | 2,336,757,089 |
Unproved | 2,623,802 | 10,007,529 |
Other Property and Equipment | 977,349 | 1,837,469 |
Total Property and Equipment | 2,432,196,199 | 2,348,602,087 |
Less – Accumulated Depreciation, Depletion and Impairment | (2,055,987,766) | (1,759,281,704) |
Total Property and Equipment, Net | 376,208,433 | 589,320,383 |
Deferred Income Taxes | 0 | 0 |
Other Noncurrent Assets, Net | 8,430,359 | 10,080,846 |
Total Assets | 431,532,961 | 721,430,948 |
Current Liabilities: | ||
Accounts Payable | 56,146,847 | 65,319,170 |
Accrued Expenses | 6,094,938 | 7,893,975 |
Accrued Interest | 4,682,894 | 4,713,232 |
Derivative Instruments | 10,001,564 | 0 |
Asset Retirement Obligations | 517,423 | 188,770 |
Total Current Liabilities | 77,443,666 | 78,115,147 |
Long-term Debt, Net | 832,625,125 | 835,290,329 |
Derivative Instruments | 1,738,329 | 0 |
Asset Retirement Obligations | 6,990,877 | 5,627,586 |
Other Noncurrent Liabilities | 156,632 | 0 |
TOTAL LIABILITIES | 918,954,629 | 919,033,062 |
COMMITMENTS AND CONTINGENCIES (NOTE 8) | ||
STOCKHOLDERS’ DEFICIT | ||
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding | 0 | 0 |
Common Stock, Par Value $.001; 142,500,000 Authorized (12/31/2016 – 63,259,781 Shares Outstanding and 12/31/2015 – 63,120,384 Shares Outstanding) | 63,260 | 63,120 |
Additional Paid-In Capital | 443,895,032 | 440,221,018 |
Retained Deficit | (931,379,960) | (637,886,252) |
Total Stockholders’ Deficit | (487,421,668) | (197,602,114) |
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT | $ 431,532,961 | $ 721,430,948 |
BALANCE SHEETS (Parenthetical)
BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
Statement of Financial Position [Abstract] | ||
Preferred Stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Preferred Stock, shares authorized (in shares) | 5,000,000 | 5,000,000 |
Preferred Stock, shares outstanding (in shares) | 0 | 0 |
Common Stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Common Stock, shares authorized (in shares) | 142,500,000 | 142,500,000 |
Common Stock, shares outstanding (in shares) | 63,259,781 | 63,120,384 |
STATEMENTS OF OPERATIONS
STATEMENTS OF OPERATIONS - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
REVENUES | |||
Oil and Gas Sales | $ 159,690,883 | $ 202,638,640 | $ 431,605,015 |
Gain (Loss) on Derivative Instruments, Net | (14,818,734) | 72,382,907 | 163,412,615 |
Other Revenue | 31,347 | 35,866 | 9,112 |
Total Revenues | 144,903,496 | 275,057,413 | 595,026,742 |
OPERATING EXPENSES | |||
Production Expenses | 45,680,110 | 52,107,984 | 55,695,615 |
Production Taxes | 15,513,608 | 21,566,634 | 43,674,010 |
General and Administrative Expense | 14,757,641 | 19,042,004 | 17,602,306 |
Depletion, Depreciation, Amortization and Accretion | 61,244,158 | 137,769,812 | 172,883,554 |
Impairment of Oil and Natural Gas Properties | 237,012,834 | 1,163,959,246 | 0 |
Total Expenses | 374,208,351 | 1,394,445,680 | 289,855,485 |
INCOME (LOSS) FROM OPERATIONS | (229,304,855) | (1,119,388,267) | 305,171,257 |
OTHER INCOME (EXPENSE) | |||
Interest Expense, Net of Capitalization | (64,485,623) | (58,360,387) | (42,105,676) |
Write-off of Debt Issuance Costs | (1,089,507) | 0 | 0 |
Other Income (Expense) | (15,902) | (30,091) | 47,364 |
Total Other Income (Expense) | (65,591,032) | (58,390,478) | (42,058,312) |
INCOME (LOSS) BEFORE INCOME TAXES | (294,895,887) | (1,177,778,745) | 263,112,945 |
INCOME TAX PROVISION (BENEFIT) | (1,402,179) | (202,424,204) | 99,367,000 |
NET INCOME (LOSS) | $ (293,493,708) | $ (975,354,541) | $ 163,745,945 |
Net Income (Loss) Per Common Share - Basic (in dollars per share) | $ (4.80) | $ (16.08) | $ 2.70 |
Net Income (Loss) Per Common Share - Diluted (in dollars per share) | $ (4.80) | $ (16.08) | $ 2.69 |
Weighted Average Shares Outstanding - Basic (in shares) | 61,173,547 | 60,652,447 | 60,691,701 |
Weighted Average Shares Outstanding - Diluted (in shares) | 61,173,547 | 60,652,447 | 60,860,769 |
STATEMENTS OF CASH FLOWS
STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net Income (Loss) | $ (293,493,708) | $ (975,354,541) | $ 163,745,945 |
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities: | |||
Depletion, Depreciation, Amortization and Accretion | 61,244,158 | 137,769,812 | 172,883,554 |
Amortization of Debt Issuance Costs | 3,822,967 | 3,696,532 | 2,776,024 |
Write-off of Debt Issuance Costs | 1,089,507 | 0 | 0 |
Amortization of 8% Senior Notes Premium/Discount | 501,324 | (248,268) | (1,486,726) |
(Gain) Loss on the Sale of Other Property & Equipment | 30,356 | (61,787) | 0 |
Deferred Income Taxes | 0 | (202,350,555) | 96,107,555 |
Loss (Gain) on the Mark-to-Market of Derivative Instruments | 76,346,935 | 88,715,603 | (171,275,719) |
Deferred Rent | 82,950 | 0 | 0 |
Amortization of Deferred Rent | (1,720) | (8,548) | (14,656) |
Share-Based Compensation Expense | 3,464,040 | 5,234,115 | 2,759,133 |
Impairment of Oil and Natural Gas Properties | 237,012,834 | 1,163,959,246 | 0 |
Other | 292,753 | 1,704,662 | 0 |
Changes in Working Capital and Other Items: | |||
Accounts Receivable | 15,604,984 | 27,701,606 | 885,262 |
Prepaid Expenses and Other | (691,261) | 2,220 | (124,348) |
Accounts Payable | (365,103) | (4,545,304) | 4,094,145 |
Accrued Interest | (90,593) | 590,630 | (106,680) |
Accrued Expenses | (1,556,673) | 210,295 | 4,014,052 |
Income Tax Receivable | (1,402,179) | 0 | 0 |
Net Cash Provided By Operating Activities | 101,891,571 | 247,015,718 | 274,257,541 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Purchases of Oil and Natural Gas Properties and Development Capital Expenditures, Net | (92,935,905) | (289,055,440) | (476,870,842) |
Proceeds from Sale of Oil and Natural Gas Properties | 2,172,003 | 138,524 | 0 |
Proceeds from Sale of Other Property and Equipment | 14,500 | 72,000 | 0 |
Purchases of Other Property and Equipment | (214,685) | (90,751) | (169,003) |
Net Cash Used For Investing Activities | (90,964,087) | (288,935,667) | (477,039,845) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Advances on Revolving Credit Facility | 63,000,000 | 150,000,000 | 253,000,000 |
Repayments on Revolving Credit Facility | (69,000,000) | (298,000,000) | (30,000,000) |
Issuance of Senior Unsecured Notes | 0 | 190,000,000 | 0 |
Debt Issuance Costs Paid | (428,515) | (5,687,596) | (434,936) |
Repurchases of Common Stock | (1,403,260) | (339,578) | (16,132,414) |
Net Cash (Used For) Provided By Financing Activities | (7,831,775) | 35,972,826 | 206,432,650 |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 3,095,709 | (5,947,123) | 3,650,346 |
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD | 3,390,389 | 9,337,512 | 5,687,166 |
CASH AND CASH EQUIVALENTS – END OF PERIOD | 6,486,098 | 3,390,389 | 9,337,512 |
Supplemental Disclosure of Cash Flow Information | |||
Cash Paid During the Period for Interest | 60,480,783 | 55,209,662 | 44,913,994 |
Cash Paid During the Period for Income Taxes | 0 | 3,258,160 | 0 |
Non-Cash Financing and Investing Activities: | |||
Oil and Natural Gas Properties Included in Accounts Payable | 50,713,195 | 59,520,415 | 221,278,750 |
Capitalized Asset Retirement Obligations | 1,353,307 | 421,394 | 952,087 |
Non-Cash Compensation Capitalized in Oil and Gas Properties | $ 971,313 | $ 1,330,693 | $ 660,615 |
STATEMENTS OF CASH FLOWS (Paren
STATEMENTS OF CASH FLOWS (Parenthetical) | Dec. 31, 2016 |
8% Senior Notes [Member] | Senior Notes [Member] | |
Debt Instrument [Line Items] | |
Interest rate percentage | 8.00% |
STATEMENTS OF STOCKHOLDERS' EQU
STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings (Deficit) [Member] |
Balance at Dec. 31, 2013 | $ 619,828,361 | $ 61,858 | $ 446,044,159 | $ 173,722,344 |
Balance (in shares) at Dec. 31, 2013 | 61,858,199 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net Issuance of Common Stock | (585,823) | $ 363 | (586,186) | |
Net Issuance of Common Stock (in shares) | 362,398 | |||
Share Based Compensation | 3,419,342 | 3,419,342 | ||
Repurchases of Common Stock | (15,546,184) | $ (1,154) | (15,545,030) | |
Repurchases of Common Stock (in shares) | (1,153,885) | |||
Net Income (Loss) | 163,745,945 | 163,745,945 | ||
Balance at Dec. 31, 2014 | 770,861,641 | $ 61,067 | 433,332,285 | 337,468,289 |
Balance (in shares) at Dec. 31, 2014 | 61,066,712 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net Issuance of Common Stock | (337,466) | $ 2,053 | (339,519) | |
Net Issuance of Common Stock (in shares) | 2,053,672 | |||
Share Based Compensation | 7,228,252 | 7,228,252 | ||
Net Income (Loss) | (975,354,541) | (975,354,541) | ||
Balance at Dec. 31, 2015 | (197,602,114) | $ 63,120 | 440,221,018 | (637,886,252) |
Balance (in shares) at Dec. 31, 2015 | 63,120,384 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net Issuance of Common Stock | (1,401,149) | $ 1,735 | (1,402,884) | |
Net Issuance of Common Stock (in shares) | 1,733,939 | |||
Restricted Stock Forfeitures | (2,155,872) | $ (1,595) | (2,154,277) | |
Restricted Stock Forfeitures (in shares) | (1,594,542) | |||
Share Based Compensation | 7,231,175 | 7,231,175 | ||
Net Income (Loss) | (293,493,708) | (293,493,708) | ||
Balance at Dec. 31, 2016 | $ (487,421,668) | $ 63,260 | $ 443,895,032 | $ (931,379,960) |
Balance (in shares) at Dec. 31, 2016 | 63,259,781 |
ORGANIZATION AND NATURE OF BUSI
ORGANIZATION AND NATURE OF BUSINESS | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
ORGANIZATION AND NATURE OF BUSINESS | ORGANIZATION AND NATURE OF BUSINESS Northern Oil and Gas, Inc. (the “Company,” “Northern,” “our” and words of similar import), a Minnesota corporation, is an independent energy company engaged in the acquisition, exploration, exploitation, development and production of crude oil and natural gas properties. The Company’s common stock trades on the NYSE MKT market under the symbol “NOG”. Northern’s principal business is crude oil and natural gas exploration, development, and production with operations in North Dakota and Montana that primarily target the Bakken and Three Forks formations in the Williston Basin of the United States. The Company acquires leasehold interests that comprise of non-operated working interests in wells and in drilling projects within its area of operations. As of December 31, 2016 , approximately 79% of Northern’s 155,016 total net acres were developed. |
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
SIGNIFICANT ACCOUNTING POLICIES | SIGNIFICANT ACCOUNTING POLICIES These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In connection with preparing the financial statements for the year ended December 31, 2016 , the Company has evaluated subsequent events for potential recognition and disclosure through the date of this filing and determined that there were no subsequent events which required recognition or disclosure in the financial statements through the date of this filing. Use of Estimates The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved crude oil and natural gas reserve volumes, future development costs, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, impairment of oil and natural gas properties, and deferred income taxes. Actual results may differ from those estimates. Reclassifications Certain prior period balances in the balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net loss, cash flows or stockholders’ deficit previously reported. Cash and Cash Equivalents Northern considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than $250,000 , the Company does not have FDIC coverage on the entire amount of bank deposits. The Company believes this risk is minimal. In addition, the Company is subject to Security Investor Protection Corporation (“SIPC”) protection on a vast majority of its financial assets. Accounts Receivable Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. Accounts receivable not expected to be collected within the next twelve months are included within Other Noncurrent Assets, Net on the balance sheets. As of December 31, 2016 and 2015 , the allowance for doubtful accounts was $4.9 million and $4.5 million , respectively. The amount charged to operations for doubtful accounts was $0.8 million , $6.2 million and $1.4 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. As of December 31, 2016 and 2015 , the amount charged against the allowance for doubtful accounts was $0.4 million and $3.5 million , respectively. As of December 31, 2016 and 2015 , the Company included accounts receivable of $6.8 million in Other Noncurrent Assets, Net due to their long-term nature. Advances to Operators The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. Other Property and Equipment Property and equipment that are not crude oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than crude oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-crude oil and natural gas long-lived assets. Depreciation expense was $0.2 million , $0.3 million , and $0.3 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Oil and Gas Properties Northern follows the full cost method of accounting for crude oil and natural gas operations whereby all costs related to the exploration and development of crude oil and natural gas properties are capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2016 , 2015 and 2014 , respectively: Years Ended December 31, 2016 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ 1,890,480 $ 2,717,913 $ 2,153,448 Capitalized Interest Costs 356,196 1,506,172 4,409,544 Total $ 2,246,676 $ 4,224,085 $ 6,562,992 As of December 31, 2016 , the Company held leasehold interests in the Williston Basin on acreage located in North Dakota and Montana targeting the Bakken and Three Forks formations. Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. In the years ended December 31, 2016 , 2015 and 2014 , there were no property sales that resulted in a significant alteration. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing twelve-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives designated as hedges for accounting purposes, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. As a result of low commodity prices and their effect on the proved reserve values of properties, the Company recorded non-cash ceiling test impairments for the years ended December 31, 2016 and 2015 of $237.0 million , and $1.2 billion , respectively. The Company did not have any impairment of its proved oil and gas properties during 2014 . The impairment charges affected the Company’s reported net income but did not reduce the Company’s cash flow. If a significantly lower pricing environment reoccurs, we expect we could be required to further writedown the value of our oil and natural gas properties. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine the Company’s actual ceiling test calculation and impairment analyses in future periods. Capitalized costs associated with impaired properties and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized on the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations. For the years ended December 31, 2016 , 2015 and 2014 , the Company expired leases of $13.4 million , $19.0 million , and $26.3 million , respectively. At December 31, 2016 , the Company performed an impairment review using prices that reflect an average of 2016 ‘s monthly prices as prescribed pursuant to the SEC’s guidelines. If lower average monthly pricing is reflected in the trailing twelve-month average pricing calculation, the present value of the Company’s future net revenues could decline and further impairment could be recognized. SEC defined prices for each quarter-end in 2016 were as follows: SEC Defined Prices for 12-Months Ended NYMEX Oil Price (per Bbl) Henry Hub Gas Price (per MMBtu) December 31, 2016 $ 42.75 $ 2.49 September 30, 2016 41.68 2.28 June 30, 2016 43.12 2.24 March 31, 2016 46.26 2.39 Asset Retirement Obligations The Company accounts for its abandonment and restoration liabilities under Financial Accounting Standards Board (“FASB”) ASC Topic 410, “Asset Retirement and Environmental Obligations” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. Business Combinations The Company accounts for its acquisitions that qualify as a business using the acquisition method under FASB ASC Topic 805, “Business Combinations.” Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain. Debt Issuance Costs Debt issuance costs include origination, legal and other fees to issue debt in connection with the Company’s credit facility and senior unsecured notes. These debt issuance costs are being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method (see Note 4). The amortization of debt issuance costs for the years ended December 31, 2016 , 2015 and 2014 was $3.8 million , $3.7 million and $2.8 million , respectively. During the year ended December 31, 2016 , $1.1 million of debt issuance costs were written-off as a result of a reduction in the borrowing base of the Revolving Credit Facility, which became effective in May 2016 and was due to the impact that lower commodity prices had on our oil and gas reserve valuation. There were no debt issuance costs written-off during the years ended December 31, 2015 and 2014 , respectively. As a result of the adoption of ASU No. 2015-03 , “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”), the Company reclassified unamortized debt issuance costs associated with its 8% Senior Notes, which totaled $12.5 million as of December 31, 2015 , from “Debt Issuance Costs, Net” to a reduction of “Long-term Debt, Net” on the balance sheets. Adoption of ASU 2015-03 had no impact on the Company’s current and previously reported stockholders’ deficit, results of operations, or cash flows. Unamortized debt issuance costs associated with the Company’s revolving credit facility, which amounted to $1.6 million and $3.3 million as of December 31, 2016 and 2015 , respectively, were not reclassified and remain reflected in “Other Noncurrent Assets, Net” on the balance sheets. Bond Premium/Discount on Senior Notes On May 13, 2013, the Company recorded a bond premium of $10.5 million in connection with the “ 8% Senior Notes Due 2020” (see Note 4). This bond premium is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization of the bond premium was $1.5 million for each of the years ended December 31, 2016 , 2015 and 2014 . On May 18, 2015, the Company recorded a bond discount of $10.0 million in connection with the “ 8% Senior Notes Due 2020” (see Note 4). This bond discount is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization of the bond discount for the years ended December 31, 2016 , 2015 and 2014 was $2.0 million , $1.2 million and zero , respectively. Revenue Recognition The Company recognizes crude oil and natural gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2016 , 2015 and 2014 , the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells. Concentrations of Market and Credit Risk The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. The Company operates in the exploration, development and production sector of the crude oil and natural gas industry. The Company’s receivables include amounts due from purchasers of its crude oil and natural gas production. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its counterparties is generally high. In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk. Restructuring Costs The Company accounts for restructuring costs in accordance with FASB ASC Topic 420, “Exit or Disposal Cost Obligations.” Under these standards, the costs associated with restructuring are recorded during the period in which the liability is incurred. During the year ended December 31, 2015 , the Company recognized $0.5 million in restructuring costs for employee severance and related benefit costs incurred as part of a reduction in workforce and the closing of its Denver office, which included $0.1 million of non-cash expense related to acceleration of certain equity awards previously granted under the Company’s 2013 Incentive Plan. There were no restructuring costs incurred for the years ended December 31, 2016 and 2014 , respectively. Stock-Based Compensation The Company records expense associated with the fair value of stock-based compensation. For fully vested stock and restricted stock grants the Company calculates the stock-based compensation expense based upon estimated fair value on the date of grant. In determining the fair value of performance-based share awards, the Company utilizes a Monte Carlo simulation prepared by an independent third party. For stock options, the Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate. Stock Issuance The Company records any stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable. Income Taxes The Company’s income tax expense, deferred tax assets and deferred tax liabilities reflect management’s best assessment of estimated current and future taxes to be paid. The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The Company’s only taxing jurisdiction is the United States (federal and state). Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future. In evaluating the Company’s ability to recover its deferred tax assets, the Company considers all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, the Company begins with historical results and incorporates assumptions about the amount of future state and federal pretax operating income adjusted for items that do not have tax consequences. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. In assessing the need for a valuation allowance for the Company’s deferred tax assets, a significant item of negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2016 , driven primarily by the full cost ceiling impairments over that period. Additionally, the Company’s revenue, profitability and future growth are substantially dependent upon prevailing and future prices for oil and natural gas. The markets for these commodities continue to be volatile. Changes in oil and natural gas prices have a significant impact on the value of the Company’s reserves and on its cash flows. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond the Company’s control. Due to these factors, management has placed a lower weight on the prospect of future earnings in its overall analysis of the valuation allowance. In determining whether to establish a valuation allowance on the Company’s deferred tax assets, management concluded that the objectively verifiable evidence of cumulative negative earnings for the three-year period ended December 31, 2016 , is difficult to overcome with any forms of positive evidence that may exist. Accordingly, the valuation allowance against the Company’s deferred tax asset at December 31, 2016 and 2015 was $341.3 million and $232.3 million , respectively. No valuation allowance was recorded at December 31, 2014 . Net Income Per Common Share Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options and restricted stock. The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method. The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the years ended December 31, 2016 , 2015 and 2014 are as follows: Years Ended December 31, 2016 2015 2014 Weighted Average Common Shares Outstanding – Basic 61,173,547 60,652,447 60,691,701 Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock — — 169,068 Weighted Average Common Shares Outstanding – Diluted 61,173,547 60,652,447 60,860,769 Restricted Stock and Stock Options Excluded From EPS Due To The Anti-Dilutive Effect 829,313 322,393 15,590 As of December 31, 2016 , 2015 and 2014 , potentially dilutive shares from stock options were 391,872 , 141,872 , and 141,872 , respectively. There options were all exercisable at December 31, 2016 , 2015 and 2014 . The Company also has potentially dilutive shares from restricted stock grants outstanding of 1,905,104 , 2,365,396 , and 538,499 at December 31, 2016 , 2015 and 2014 , respectively. Derivative Instruments and Price Risk Management The Company uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil. The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date. The Company follows the provisions of FASB ASC 815, “Derivatives and Hedging” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value and marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations. See Note 13 for a description of the derivative contracts into which the Company has entered. Impairment Long-lived assets to be held and used are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Crude oil and natural gas properties accounted for using the full cost method of accounting are excluded from this requirement but continue to be subject to the full cost method’s impairment rules. In 2016 and 2015 , the Company recorded $237.0 million and $1.2 billion , respectively, in impairment related to crude oil and natural gas properties. There was no impairment related to crude oil and natural gas properties in 2014. There was no impairment of other long-lived assets recorded for the years ended December 31, 2016 , 2015 and 2014 . New Accounting Pronouncements From time to time, new accounting pronouncements are issued by the FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers . The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in United States GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers – Deferral of the Effective Date,” which approved a one year deferral of ASU 2014-09 for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early application is permitted as of the original effective date for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company will adopt this ASU on January 1, 2018. The Company is evaluating the impact of this ASU on our financial statements and, based on the continuing evaluation of our revenue streams, this ASU is not expected to have a material impact on our financial statements. The Company expects it will use the modified retrospective approach to implementation. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The standard requires lessees to recognize the assets and liabilities that arise from leases on the balance sheet. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The new guidance is effective for annual and interim reporting periods beginning after December 15, 2018. The amendments should be applied at the beginning of the earliest period presented using a modified retrospective approach with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact of the new guidance on our financial statements, however, based on our current operating leases, it is not expected to have a material impact. In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting , which relates to the accounting for employee share-based payments. This standard addresses several aspects of the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company elected to early-adopt this guidance in the fourth quarter of 2016 utilizing the adoption methods required by the ASU. The Company will continue its current accounting policy for forfeitures. See Note 10 for discussion of additional accounting consequences related to the adoption of this ASU. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This guidance rescinds SEC Staff Observer comments that are codified in Topic 606, Revenue Recognition, and Topic 932, Extractive Activities--Oil and Gas. This amendment is effective upon adoption of Topic 606. The Company is in the process of evaluating the impact of this guidance on our financial statements. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments . This guidance provides guidance of eight specific cash flow issues. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on our financial statements. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. This guidance updates narrow aspects of the guidance issued in Update 2014-09. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this ASU on our financial statements. |
CRUDE OIL AND NATURAL GAS PROPE
CRUDE OIL AND NATURAL GAS PROPERTIES | 12 Months Ended |
Dec. 31, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
CRUDE OIL AND NATURAL GAS PROPERTIES | CRUDE OIL AND NATURAL GAS PROPERTIES The value of the Company’s crude oil and natural gas properties consists of all acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets based on their estimated fair value at the time of the acquisition. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. Development capital expenditures and purchases of properties that were in accounts payable and not yet paid in cash at December 31, 2016 and 2015 were approximately $50.7 million and $59.5 million , respectively. 2016 Acquisitions During 2016 , the Company acquired approximately 3,399 net acres, for an average cost of approximately $1,515 per net acre, in its key prospect areas in the form of effective leases. On October 6, 2016, the Company entered into a definitive purchase and sale agreement with a third party, for their interests in 144 gross ( 3.8 net) producing oil and gas wells and associated acreage. The motivation for the acquisition was the expectation that it was accretive to cash flow and earnings per share. On October 26, 2016, the Company closed the transaction for cash consideration of $9.4 million which is comprised of $8.9 million related to producing properties and a $0.5 million reimbursement of drilling costs on in process wells. The results of operations from the October 26, 2016 closing date through December 31, 2016 , represented approximately $1.2 million of revenue and $0.5 million of direct operating expenses. The combined pro forma information has not been presented due to its immateriality. No material transaction costs were incurred in connection with this purchase and there was no goodwill recorded from this acquisition. 2015 Acquisitions During 2015 , the Company acquired approximately 4,355 net acres, for an average cost of approximately $1,314 per net acre, in its key prospect areas in the form of effective leases. 2014 Acquisitions During 2014 , the Company acquired approximately 22,668 net acres, for an average cost of approximately $1,534 per net acre, in its key prospect areas in the form of effective leases. Divestitures From time-to-time the Company may divest assets. In addition, the Company may trade leasehold interests with operators to balance working interests in spacing units to facilitate and encourage a more expedited development of the Company’s acreage. Unproved Properties Unproved properties not being amortized comprise approximately 26,432 net acres and 38,003 net acres of undeveloped leasehold interests at December 31, 2016 and 2015 , respectively. The Company believes that the majority of its unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves. Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years . The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2016 by year incurred. Years Ended December 31, 2016 2015 2014 Prior Years Property Acquisition $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 Development — — — — Total $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion. Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion. The Company historically has acquired its properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. The Company generally participates in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling. The Company assesses all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization. For the years ended December 31, 2016 , 2015 and 2014 , the Company included $7.0 million , $37.6 million and $21.4 million , respectively, related to expiring leases within costs subject to the depletion calculation. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil and Natural Gas Exploration and Production Activities Oil and gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of crude oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company’s crude oil and natural gas production activities are provided in the Company’s related statements of income. Costs Incurred and Capitalized Costs The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below. Years Ended December 31, 2016 2015 2014 Costs Incurred for the Year: Proved Property Acquisition and Other $ 18,531,518 $ 9,068,139 $ 29,838,482 Unproved Property Acquisition 2,301,285 3,346,214 27,561,901 Development 63,621,429 116,255,535 479,472,251 Total $ 84,454,232 $ 128,669,888 $ 536,872,634 Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2016 by year incurred. Years Ended December 31, 2016 2015 2014 Prior Years Property Acquisition $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 Development — — — — Total $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 Oil and Natural Gas Reserves and Related Financial Data Information with respect to the Company’s crude oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Ryder Scott Company, independent petroleum consultants based on information provided by the Company. Oil and Natural Gas Reserve Data The following tables present the Company’s independent petroleum consultants’ estimates of its proved crude oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Natural Gas Oil BOE Proved Developed and Undeveloped Reserves at December 31, 2013 50,168,133 75,799,125 84,160,481 Revisions of Previous Estimates 2,465,251 (11,397,088 ) (10,986,213 ) Extensions, Discoveries and Other Additions 21,984,514 29,662,181 33,326,267 Production (3,682,781 ) (5,150,913 ) (5,764,710 ) Proved Developed and Undeveloped Reserves at December 31, 2014 70,935,117 88,913,305 100,735,825 Revisions of Previous Estimates (23,552,809 ) (36,277,018 ) (40,202,486 ) Extensions, Discoveries and Other Additions 8,170,259 9,346,864 10,708,574 Production (4,651,583 ) (5,168,687 ) (5,943,951 ) Proved Developed and Undeveloped Reserves at December 31, 2015 50,900,984 56,814,464 65,297,962 Revisions of Previous Estimates (8,697,825 ) (13,995,801 ) (15,445,439 ) Extensions, Discoveries and Other Additions 7,695,309 7,142,439 8,424,991 Purchases of Minerals in Place 960,758 640,108 800,234 Production (4,026,899 ) (4,325,919 ) (4,997,069 ) Proved Developed and Undeveloped Reserves at December 31, 2016 46,832,327 46,275,291 54,080,679 Proved Developed Reserves: December 31, 2013 20,642,967 32,043,405 35,483,900 December 31, 2014 38,277,770 44,666,408 51,046,037 December 31, 2015 33,619,954 36,573,821 42,177,147 December 31, 2016 32,808,111 32,245,139 37,713,158 Proved Undeveloped Reserves: December 31, 2013 29,525,166 43,755,720 48,676,581 December 31, 2014 32,657,347 44,246,897 49,689,788 December 31, 2015 17,281,030 20,240,643 23,120,815 December 31, 2016 14,024,216 14,030,152 16,367,521 Proved reserves are estimated quantities of crude oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years. Notable changes in proved reserves for the year ended December 31, 2016 included the following: • Extensions and discoveries . In 2016 , total extensions and discoveries of 8.4 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in these areas as well as the proved undeveloped locations added as a result of drilling increased the Company’s proved reserves. • Purchases of minerals in place . In 2016 , total purchases of minerals in place of 0.8 MMBOE were primarily attributable to an acquisition with a third party (See Note 3). • Revisions to previous estimates . In 2016 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 15.4 MMBOE. Included in these revisions were 15.7 MMBOE of downward adjustments caused by lower crude oil and natural gas prices and 3.4 MMBOE of downward adjustments related to the removal of undeveloped drilling locations related to the 5 year rule which was partially offset by a 3.6 MMBOE upward adjustment attributable to well performance when comparing the Company’s reserve estimates at December 31, 2016 to December 31, 2015 . Notable changes in proved reserves for the year ended December 31, 2015 included the following: • Extensions and discoveries . In 2015 , total extensions and discoveries of 10.7 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in these areas as well as the proved undeveloped locations added as a result of drilling increased the Company’s proved reserves. • Revisions to previous estimates . In 2015 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 40.2 MMBOE. Included in these revisions were 52.6 MMBOE of downward adjustments caused by lower crude oil and natural gas prices and 12.4 MMBOE of net upward adjustments attributable to reservoir analysis and well performance when comparing the Company’s reserve estimates at December 31, 2015 to December 31, 2014. Notable changes in proved reserves for the year ended December 31, 2014 included the following: • Extensions and discoveries . In 2014 , total extensions and discoveries of 33.3 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in these areas as well as the proved undeveloped locations added as a result of drilling increased the Company’s proved reserves. • Revisions to previous estimates . In 2014 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 11.0 MMBOE. Included in these revisions were 0.9 MMBOE of net upward adjustments attributable to well performance and 2.1 MMBOE of downward adjustments caused by lower crude oil prices and 9.8 MMBOE downward adjustments attributable to reservoir analysis when comparing the Company’s reserve estimates at December 31, 2014 to December 31, 2013. Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein The following table presents a standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating proved crude oil and natural gas were prepared in accordance with the provisions of ASC 932 Extractive Activities - Oil and Gas . Future cash inflows were computed by applying average prices of crude oil and natural gas for the last 12 months to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year end tax rates to future pretax cash flows relating to proved crude oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carry forwards relating to crude oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s crude oil and natural gas reserves. Years Ended December 31, 2016 2015 2014 Future Cash Inflows $ 1,708,870,912 $ 2,470,707,712 $ 7,912,622,500 Future Production Costs (775,534,832 ) (981,256,096 ) (2,281,320,000 ) Future Development Costs (220,869,664 ) (356,401,888 ) (1,453,562,125 ) Future Income Tax Expense (2,477,353 ) (5,740,623 ) (1,058,511,086 ) Future Net Cash Inflows $ 709,989,063 $ 1,127,309,105 $ 3,119,229,289 10% Annual Discount for Estimated Timing of Cash Flows (330,963,050 ) (552,510,342 ) (1,713,849,746 ) Standardized Measure of Discounted Future Net Cash Flows $ 379,026,013 $ 574,798,763 $ 1,405,379,543 The twelve month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The price of other liquids is included in natural gas. The prices for the Company’s reserve estimates were as follows: Natural Gas MCF Oil Bbl December 31, 2016 $ 1.67 $ 35.24 December 31, 2015 $ 1.63 $ 42.03 December 31, 2014 $ 7.37 $ 83.11 The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows. As a result of available net operating loss carryforwards and the remaining tax basis of its assets at December 31, 2016 , the Company’s future income taxes were significantly reduced. Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow: Years Ended December 31, 2016 2015 2014 Beginning of Period $ 574,798,763 $ 1,405,379,543 $ 1,224,366,826 Sales of Oil and Natural Gas Produced, Net of Production Costs (98,497,165 ) (128,964,023 ) (330,395,323 ) Extensions and Discoveries 59,542,911 96,770,078 567,026,734 Previously Estimated Development Cost Incurred During the Period 23,271,960 114,208,095 205,125,299 Net Change of Prices and Production Costs (174,656,448 ) (1,384,474,928 ) (52,577,882 ) Change in Future Development Costs 57,481,060 235,578,690 (64,185,447 ) Revisions of Quantity and Timing Estimates (130,664,183 ) (363,975,445 ) (326,674,460 ) Accretion of Discount 57,569,313 170,222,344 152,128,992 Change in Income Taxes 497,950 295,949,531 (79,196 ) Purchases of Minerals in Place 9,576,760 — — Other 105,092 134,104,878 30,644,000 End of Period $ 379,026,013 $ 574,798,763 $ 1,405,379,543 |
LONG TERM DEBT
LONG TERM DEBT | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
LONG TERM DEBT | LONG TERM DEBT The Company’s long-term debt consists of the following: December 31, 2016 Long-term Debt Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 698,306,153 $ (9,681,028 ) $ 688,625,125 Revolving Credit Facility (1) 144,000,000 — 144,000,000 Total $ 842,306,153 $ (9,681,028 ) $ 832,625,125 December 31, 2015 Long-term Debt Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 697,804,829 $ (12,514,500 ) $ 685,290,329 Revolving Credit Facility (1) 150,000,000 — 150,000,000 Total $ 847,804,829 $ (12,514,500 ) $ 835,290,329 _____________ (1) Debt issuance costs related to our revolving credit facility are recorded in “Other Noncurrent Assets, Net” on the balance sheets Revolving Credit Facility In February 2012, the Company entered into an amended and restated credit agreement providing for a revolving credit facility (the “Revolving Credit Facility”), which replaced its previous revolving credit facility with a syndicated facility. The Revolving Credit Facility, which is secured by substantially all of the Company’s assets, provides for a commitment equal to the lesser of the facility amount or the borrowing base. At December 31, 2016 , the facility amount was $750 million , the borrowing base was $350 million and there was a $144 million outstanding balance, leaving $206 million of borrowing capacity available under the facility. The Revolving Credit Facility matures on September 30, 2018 and provides for a borrowing base subject to redetermination semi-annually each April and October and for unscheduled event-driven redeterminations. Borrowings under the Revolving Credit Facility can either be at the Alternate Base Rate (as defined in the credit agreement) plus a spread ranging from 1.0% to 2.0% or LIBOR borrowings at the Adjusted LIBOR Rate (as defined in the credit agreement) plus a spread ranging from 2.0% to 3.0% . The applicable spread at any time is dependent upon the amount of borrowings relative to the borrowing base at such time. The Company may elect, from time to time, to convert all or any part of its LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans. A commitment fee is paid on the undrawn balance based on an annual rate of either 0.375% or 0.50% . At December 31, 2016 , the commitment fee was 0.375% and the interest rate margin was 2.25% on LIBOR loans and 1.25% on base rate loans. At December 31, 2016 , the Company had a borrowing base of $350 million with $144 million of LIBOR loans issued under the Revolving Credit Facility at a weighted average interest rate of 3.02% . The Revolving Credit Facility contains negative covenants that limit the Company’s ability, among other things, to pay any cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of its business or operations, merge, consolidate, make investments, or maintain excess cash liquidity. In addition, the Company is required to maintain a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0 , a ratio of secured debt to EBITDAX (as defined in the credit agreement) of no greater than 2.5 to 1.0 and a ratio of EBITDAX (as defined in the credit agreement) to interest expense (as defined in the credit agreement) of no less than 1.75 to 1.0 (through December 31, 2016 ). The Company was in compliance with the financial covenants of the Revolving Credit Facility at December 31, 2016 . The minimum ratio of EBITDAX to interest expense that the Company is required to maintain begins stepping down with the quarter ending December 31, 2016 , through the quarter ending March 31, 2018. The schedule of the minimum ratio of EBITDAX to interest expense the Company is required to maintain is as follows: Measurement Period Minimum ratio of EBITDAX to Interest Expense 12 months ending December 31, 2016 1.75 to 1.00 12 months ending March 31, 2017 1.50 to 1.00 12 months ending June 30, 2017 1.25 to 1.00 12 months ending September 30, 2017 1.25 to 1.00 12 months ending December 31, 2017 1.00 to 1.00 12 months ending March 31, 2018 1.00 to 1.00 12 months ending June 30, 2018 and beyond 2.50 to 1.00 All of the Company’s obligations under the Revolving Credit Facility are secured by a first priority security interest in any and all assets of the Company. 8.000% Senior Notes Due 2020 On May 18, 2012, the Company issued at par value $300 million aggregate principal amount of 8.000% senior unsecured notes due June 1, 2020 (the “Original Notes”). On May 13, 2013, the Company issued at a price of 105.25% of par an additional $200 million aggregate principal amount of 8.000% senior unsecured notes due June 1, 2020 (the “2013 Follow-on Notes”). On May 18, 2015, the Company issued at a price of 95.000% of par an additional $200 million aggregate principal amount of 8.000% senior unsecured notes due June 1, 2020 (the “2015 Mirror Notes” and, together with the Original Notes and the 2013 Follow-on Notes, the “Notes”). Interest is payable on the Notes semi-annually in arrears on each of June 1 and December 1. The Company currently does not have any subsidiaries and, as a result, the Notes are not currently guaranteed. Any subsidiaries the Company forms in the future may be required to unconditionally guarantee, jointly and severally, payment obligation under the Notes on a senior unsecured basis. The issuance of the Original Notes resulted in net proceeds to the Company of approximately $291.2 million , the issuance of the 2013 Follow-on Notes resulted in net proceeds to the Company of approximately $200.1 million , and the issuance of the 2015 Mirror Notes resulted in net proceeds to the Company of approximately $184.9 million . Collectively, the net proceeds are in use to fund the Company’s exploration, development and acquisition program and for general corporate purposes (including repayment of borrowings that were outstanding under the Revolving Credit Facility at the time the Notes were issued). On and after June 1, 2016, the Company may redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 104% for the twelve-month period beginning on June 1, 2016, 102% for the twelve-month period beginning June 1, 2017 and 100% beginning on June 1, 2018, plus accrued and unpaid interest to the redemption date. The Original Notes and the 2013 Follow-on Notes are governed by an Indenture, dated as of May 18, 2012, by and among the Company and Wilmington Trust, National Association (the “Original Indenture”). The 2015 Mirror Notes are governed by an Indenture, dated as of May 18, 2015, by and among the Company and Wilmington Trust, National Association (the “Mirror Indenture”). The terms and conditions of the Mirror Indenture conform, in all material respects, to the terms and conditions set forth in the Original Indenture. As such, the Mirror Indenture, together with the Original Indenture, are referred to herein as the “Indenture.” The Indenture restricts the Company’s ability to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or, repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of exceptions and qualifications. If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries (if any) will cease to be subject to such covenants. The Indenture contains customary events of default, including: • default in any payment of interest on any Note when due, continued for 30 days ; • default in the payment of principal of or premium, if any, on any Note when due; • failure by the Company to comply with its other obligations under the Indenture, in certain cases subject to notice and grace periods; • payment defaults and accelerations with respect to other indebtedness of the Company and certain of its subsidiaries, if any, in the aggregate principal amount of $25.0 million or more; • certain events of bankruptcy, insolvency or reorganization of the Company or a significant subsidiary or group of restricted subsidiaries that, taken together, would constitute a significant subsidiary; • failure by the Company or any significant subsidiary or group of restricted subsidiaries that, taken together, would constitute a significant subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days ; and • any guarantee of the Notes by a guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker. |
COMMON AND PREFERRED STOCK
COMMON AND PREFERRED STOCK | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
COMMON AND PREFERRED STOCK | COMMON AND PREFERRED STOCK In May 2016, the Company’s shareholders approved an amendment to the Company’s Articles of Incorporation to increase the number of authorized shares of common stock by 50% , from 95,000,000 to 142,500,000 . As a result, the Company’s Amended and Restated Articles of Incorporation authorize the issuance of up to 147,500,000 shares. The shares are classified in two classes, consisting of 142,500,000 shares of common stock, par value $0.001 per share, and 5,000,000 shares of preferred stock, par value $0.001 per share. The board of directors is authorized to establish one or more series of preferred stock, setting forth the designation of each such series, and fixing the relative rights and preferences of each such series. The Company has neither designated nor issued any shares of preferred stock. Common Stock The following is a schedule of changes in the number of shares of common stock outstanding since the beginning of 2014 : Years Ended December 31, 2016 2015 2014 Beginning Balance 63,120,384 61,066,712 61,858,199 Stock Options Exercised — — 100,000 Restricted Stock Grants (Note 6) 2,109,814 2,112,998 299,416 Stock Repurchased — — (1,153,885 ) Other Surrenders (375,875 ) (57,929 ) (79,461 ) Other (1,594,542 ) (1,397 ) 42,443 Ending Balance 63,259,781 63,120,384 61,066,712 2016 Activity In 2016 , 375,875 shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards. The total value of these shares was approximately $1.4 million , which is based on the market prices on the dates the shares were surrendered. In 2016 , 1,530,796 restricted shares of common stock were forfeited in connection with the termination of the employment of the Company’s former chief executive officer. The total amount of share-based compensation expense that was reversed in connection with the termination was approximately $1.8 million . 2015 Activity In 2015 , the Company’s Chief Executive Officer received 1.4 million restricted shares of common stock in connection with a new employment agreement. In 2015 , 57,929 shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards. The total value of these shares was approximately $277,000 , which is based on the market prices on the dates the shares were surrendered. In 2015 , 1,397 shares of restricted common stock were surrendered by an employee who terminated employment with the Company. 2014 Activity In 2014 , 43,835 shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards. The total value of these shares was approximately $587,000 , which is based on the market prices on the dates the shares were surrendered. In 2014 , a former director of the Company exercised an aggregate of 100,000 stock options, which were granted in 2007. Of those stock options, 35,626 shares were surrendered to cover the aggregate exercise price of approximately $518,000 , based on the market price on the date the shares were surrendered. In 2014 , there was an increase in common stock of 42,443 shares, included as “Other” within the table above, to reflect an immaterial adjustment related to a prior period, to correct the Company’s total common shares outstanding that were on record as of December 31, 2014 . Stock Repurchase Program In May 2011, the Company’s board of directors approved a stock repurchase program to acquire up to $150 million of the Company’s outstanding common stock. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions. In 2016 and 2015 , the Company did not repurchase shares of its common stock under the stock repurchase program. In 2014 , the Company repurchased of 1,153,885 shares of its common stock under the stock repurchase program which had a cost of approximately $15.5 million . All repurchased shares are included in the Company’s pool of authorized but unissued shares. The Company’s accounting policy upon the repurchase of shares is to deduct its par value from Common Stock and to reflect any excess of cost over par value as a deduction from Additional Paid-in Capital. |
STOCK OPTIONS_STOCK-BASED COMPE
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS | STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS The Company maintains its 2013 Incentive Plan (the “2013 Plan”) to provide a means whereby the Company may be able, by granting equity and other types of awards, to attract, retain and motivate capable and loyal employees, non-employee directors, consultants and advisors of the Company, for the benefit of the Company and its shareholders. In May 2016, the Company’s shareholders approved an amendment to the 2013 Plan to increase the number of shares available for awards under the 2013 Plan by 1.6 million shares. As of December 31, 2016 , there were 3.7 million shares available for future awards under the 2013 Plan. Restricted Stock Awards During the years ended December 31, 2016 , 2015 and 2014 , the Company issued 2,109,814 , 2,112,998 and 299,416 , respectively, restricted shares of common stock under the 2013 Plan as compensation to officers, employees and directors of the Company. Unvested restricted shares vest over various terms with all restricted shares vesting no later than April 2020. As of December 31, 2016 , there was approximately $9.2 million of total unrecognized compensation expense related to unvested restricted stock that will be recognized over a weighted-average period of approximately 2.4 years . The Company has historically assumed a zero percent forfeiture rate, thus recognizing forfeitures as they occur, for restricted stock due to the small number of officers, employees and directors that have received restricted stock awards. The following table reflects the outstanding restricted stock awards and activity related thereto for the years ended December 31, 2016 , 2015 and 2014 : Year Ended Year Ended Year Ended Number of Shares Weighted- Average Price Number Of Shares Weighted- Average Price Number Of Shares Weighted- Average Price Restricted Stock Awards: Restricted Shares Outstanding at the Beginning of the Year 2,365,396 $ 7.15 538,499 $ 13.54 592,565 $ 16.84 Shares Granted 2,109,814 3.83 2,112,998 6.29 299,416 12.09 Shares Forfeited (1,594,542 ) 4.67 (1,397 ) 14.79 — — Lapse of Restrictions (975,564 ) 7.34 (284,704 ) 12.24 (353,482 ) 17.84 Restricted Shares Outstanding at the End of the Year 1,905,104 $ 4.59 2,365,396 $ 7.15 538,499 $ 13.54 Stock Option Awards On November 1, 2007, the board of directors granted options to purchase 560,000 shares of the Company’s common stock under the Company’s 2006 Incentive Stock Option Plan. The Company granted options to purchase 500,000 shares of the Company’s common stock to members of the board and options to purchase 60,000 shares of the Company’s common stock to one employee pursuant to an employment agreement. These options were granted at a price of $5.18 per share and the optionees were fully vested on the grant date. As of December 31, 2016 , options to purchase a total of 141,872 shares of the Company’s common stock remain outstanding but unexercised under these awards. The board of directors determined that no future grants will be made pursuant to the 2006 Incentive Stock Option Plan. On February 12, 2016, the board of directors granted options to purchase 250,000 shares of the Company’s common stock under the Company’s 2013 Plan. The Company granted options to purchase 250,000 shares of the Company’s common stock to one of its board members in connection with his appointment as chairman of the board of directors in January 2016. These options were granted with an exercise price of $2.79 per share and were fully vested on the grant date. As a result of the options being fully vested on the grant date, the Company recorded share-based compensation expense of $0.4 million for the year ended December 31, 2016 . Changes in stock option awards for the years ended December 31, 2016 , 2015 , and 2014 were as follows: Stock Option Awards Weighted-Average Price Weighted Average Contractual Term Intrinsic Value Outstanding as of December 31, 2013 (1) 241,872 $ 5.18 3.8 $ 2,392,000 Granted — — Exercised (100,000 ) 5.18 Expired or canceled — — Forfeited — — Outstanding as of December 31, 2014 (1) 141,872 5.18 2.8 $ 66,680 Granted — — Exercised — — Expired or canceled — — Forfeited — — Outstanding as of December 31, 2015 (1) 141,872 5.18 1.8 $ — Granted 250,000 2.79 Exercised — — Expired or canceled — — Forfeited — — Outstanding as of December 31, 2016 (1) 391,872 $ 3.66 2.9 $ — ____________ (1) All of the stock options outstanding were vested and exercisable at the end of the period. The Company used the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. The Company used the simplified method to determine the expected term of the options due to the lack of sufficient historical data. Changes in these assumptions can materially affect the fair value estimate. The total fair value of the options is recognized as compensation over the vesting period. There were no stock options granted by the Company in 2015 and 2014 . The assumptions used to estimate the fair value of stock option awards granted in February, 2016 are as follows: February 12, 2016 Risk-free interest rate 1.15 % Expected life 5.0 Expected volatility 61.89 % Fair value per option: $ 1.47 Performance Equity Awards The Company has granted performance equity awards under its 2016 Long Term Incentive Program to certain officers. The awards are subject to a market condition, which is based on a comparison of the Company versus a defined peer group with respect to year-over-year change in average stock price from 2015 to 2016 . Depending on the Company’s stock price performance relative to the defined peer group, the award recipients will earn between 0% and 150% of their 2016 base salaries and will be settled in restricted shares of the Company’s common stock that will vest over a three -year service-based period beginning in 2017 . The Company used a Monte Carlo simulation model to estimate the fair value of the awards based on the expected outcome of the Company’s stock price performance relative to the defined peer group using key valuation assumptions. The assumptions used for the Monte Carlo model to determine the fair value of the awards and associated compensation expense included a forecast period of one year, a risk-free interest rate of 0.49% and 83.3% for Northern’s stock price volatility. The maximum value of the performance shares issuable if all participants earned the maximum award would total $1.7 million . For the year ended December 31, 2016 , the Company recorded $0.1 million of compensation expense in connection with these performance awards. |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS Michael Frantz, a member of the Company’s board of directors since August 2016, is the Vice President, Investments of TRT Holdings, Inc. Michael Popejoy, a member of the Company’s board of directors since January 2017, is the Senior Vice President of Energy for TRT Holdings, Inc. TRT Holdings and its affiliates (collectively, “TRT”) are significant common stockholders of the Company and also a holder of the Company’s 8% senior unsecured notes, due 2020 (the “Notes”). The Company believes TRT owned in excess of $200 million of the Notes at December 31, 2016 . The principal amounts of any Notes held by TRT are included in the Company’s long-term debt balances, and the Company’s interest expense includes interest attributable to any Notes held by TRT. All transactions involving related parties are approved or ratified by the Company’s Audit Committee. |
COMMITMENTS & CONTINGENCIES
COMMITMENTS & CONTINGENCIES | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS & CONTINGENCIES | COMMITMENTS & CONTINGENCIES Litigation The Company is engaged in various proceedings incidental to the normal course of business. Due to their nature, such legal proceedings involve inherent uncertainties, including but not limited to, court rulings, negotiations between affected parties and governmental intervention. Based upon the information available to the Company and discussions with legal counsel, it is the Company’s opinion that the outcome of the various legal actions and claims that are incidental to its business will not have a material impact on the Company’s financial position, results of operations or cash flows. Such matters, however, are subject to many uncertainties, and the outcome of any matter is not predictable with assurance. The Company’s interests in certain crude oil and natural gas leases from the State of North Dakota are subject to an ongoing dispute over the ownership of minerals underlying the bed of the Missouri River within the boundaries of the Fort Berthold Reservation. The ongoing dispute is between the State of North Dakota and three affiliated tribes, both of whom have purported to lease mineral rights in tracts of riverbed within the reservation boundaries. In the event the ongoing dispute results in a final judgment that is adverse to the Company’s interests, the Company would be required to reverse approximately $6.8 million in revenue (net of accrued taxes) that has been accrued since the first quarter of 2013 based on the Company’s purported interest in the crude oil and natural gas leases at issue. Due to the long-term nature of this title dispute, the $6.8 million in accounts receivable is included in “Other Noncurrent Assets, Net” on the balance sheets. The Company fully maintains the validity of its interests in the crude oil and natural gas leases. On August 16, 2016, Michael Reger filed a complaint against the Company in the State of Minnesota, Fourth Judicial District, alleging breach of contract and defamation in connection with the Company’s termination of Mr. Reger’s employment as chief executive officer on August 15, 2016. Mr. Reger’s complaint alleges that the Company breached his employment agreement by, among other things, purporting to terminate him for cause, removing him from the Company’s board of directors based on such termination, and denying him payments and other benefits to which he alleges that he is entitled under the employment agreement (including payments and benefits in connection with a termination without cause). Mr. Reger is seeking unspecified damages, an order reinstating him to the Company’s board of directors, and other equitable relief. Among other damages that Mr. Reger may seek, including damages for defamation, the Company expects him to seek benefits to which he alleges he should have been entitled for a termination without cause, which may have included at least $1.6 million in cash severance and the immediate vesting of 1,530,796 shares of restricted stock held by Mr. Reger at the time of his termination. On August 18, 2016, plaintiff Jeffrey Fries, individually and on behalf of all others similarly situated, filed a class action complaint in the United States District Court for the Southern District of New York against our Company, Michael Reger (our former chief executive officer), and Thomas Stoelk (our chief financial officer and interim chief executive officer) as defendants. The complaint purports to bring a federal securities class action on behalf of the class of persons who acquired the Company’s securities between March 1, 2013 and August 15, 2016, and seeks to recover damages caused by defendants’ alleged violations of federal securities laws and to pursue remedies under Sections 10(a) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. |
ASSET RETIREMENT OBLIGATION
ASSET RETIREMENT OBLIGATION | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation [Abstract] | |
ASSET RETIREMENT OBLIGATION | ASSET RETIREMENT OBLIGATION The Company has asset retirement obligations (“ARO”) associated with the future plugging and abandonment of proved properties and related facilities. Initially, the fair value of a liability for an ARO is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO, a corresponding adjustment is made to the oil and gas property balance. For example, as the Company analyzes actual plugging and abandonment information, the Company may revise its estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of its wells. During 2016 , the Company increased its existing ARO by $0.8 million at December 31, 2016 . This increase was due to an increase in the estimated costs to plug and abandon the Company’s wells. During 2015 , the Company decreased its existing ARO by $0.1 million at December 31, 2015 . This decrease was due to a decrease in the productive life of certain of its oil and gas properties. The following table summarizes the Company’s asset retirement obligation transactions recorded during the year ended December 31, 2016 and 2015 . Years Ended December 31, 2016 2015 Beginning Asset Retirement Obligation $ 5,816,356 $ 5,105,762 Liabilities Acquired or Incurred During the Period 585,729 475,306 Liabilities Removed Due to Divestitures (21,426 ) — Revision of Estimates 789,003 (53,912 ) Accretion of Discount on Asset Retirement Obligations 405,991 372,461 Liabilities Settled During the Period (67,353 ) (83,261 ) Ending Asset Retirement Obligation $ 7,508,300 $ 5,816,356 |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. The income tax provision (benefit) for the year ended December 31, 2016 , 2015 , and 2014 consists of the following: 2016 2015 2014 Current $ (1,402,179 ) $ (73,649 ) $ 3,259,445 Deferred Federal (99,298,900 ) (398,002,555 ) 87,625,430 State (9,707,000 ) (36,608,000 ) 8,482,125 Valuation Allowance 109,005,900 232,260,000 — Total Expense (Benefit) $ (1,402,179 ) $ (202,424,204 ) $ 99,367,000 The following is a reconciliation of the reported amount of income tax expense for the years ended December 31, 2016 , 2015 , and 2014 to the amount of income tax expenses that would result from applying the statutory rate to pretax income. 2016 2015 2014 Income (Loss) Before Taxes and NOL $ (294,895,887 ) $ (1,177,778,745 ) $ 263,112,945 Federal Statutory Rate 35.00 % 35.00 % 35.00 % Taxes Computed at Federal Statutory Rates (103,214,000 ) (412,223,000 ) 92,090,000 State Taxes, Net of Federal Taxes (6,306,000 ) (23,825,000 ) 5,404,300 Non-Deductible Compensation 82,000 470,000 456,000 Share Based Compensation Tax Deficiency (834,900 ) 307,000 1,472,000 Other (135,179 ) 586,796 (55,300 ) Valuation Allowance 109,005,900 232,260,000 — Reported Provision (Benefit) $ (1,402,179 ) $ (202,424,204 ) $ 99,367,000 A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During 2016 , in evaluating whether it was more likely than not that the Company’s net deferred tax assets were realized through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil and natural gas. Based on all the evidence available, management determined it was more likely than not that the net deferred tax assets were not realizable, therefore a valuation allowance of $341.3 million was recorded at December 31, 2016 . At December 31, 2016 , the Company had a net operating loss carryforward for federal income tax purposes of $605.4 million . If unutilized, the federal net operating losses will expire from 2027 to 2036 . At December 31, 2016 , the Company had an alternative minimum tax credit for federal income tax purpose of $1.7 million . This credit carryforward does not expire. The significant components of the Company’s deferred tax assets (liabilities) were as follows: Years Ended December 31, 2016 2015 Net Operating Loss (NOLs) and Tax Credit Carryforwards $ 224,679,900 $ 195,207,000 Share Based Compensation 1,032,000 1,762,000 Accrued Interest 1,727,000 1,723,000 Allowance for Doubtful Accounts 1,795,000 1,662,000 Crude Oil and Natural Gas Properties and Other Properties 107,642,000 55,939,000 Derivative Instruments 4,341,000 (23,855,000 ) Other 49,000 (178,000 ) Total Net Deferred Tax Assets (Liabilities) Before Valuation Allowance 341,265,900 232,260,000 Valuation Allowance (341,265,900 ) (232,260,000 ) Total Net Deferred Tax Assets (Liabilities) $ — $ — Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards. The Company has no liabilities for unrecognized tax benefits. The Company’s policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense. For the years ended December 31, 2016 , 2015 and 2014 , the Company did not recognize any interest or penalties in its statements of operations, nor did it have any interest or penalties accrued in its balance sheet at December 31, 2016 and 2015 relating to unrecognized benefits. The tax years 2016 , 2015 , 2014 , 2013 , 2012, 2011 and 2010 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company is subject. The Protecting Americans from Tax Hikes Act of 2015 (PATH) was enacted on December 18, 2015. PATH retroactively extended various temporary individual and business tax incentives for 2015 and in some instances extended certain incentives through 2019. Bonus tax depreciation, a favorable tax incentive for the Company, was extended from 2015 through 2019. In 2016 , the Company utilized $1.4 million of its alternative minimum tax credit as a result of favorable tax incentives within PATH. The Company early-adopted a new accounting standard that simplified the accounting for stock-based compensation. As a result, the Company recorded a cumulative-effect adjustment to retained earnings as of January 1, 2016 for all windfall tax benefits that were not previously recognized because the related tax deduction had not reduced current taxes payable. The resulting deferred tax asset was assessed for realizability in accordance with GAAP. Due to the Company’s valuation allowance position, a cumulative-effect adjustment was recorded to retained earnings as of January 1, 2016, and therefore, the net effect of the early-adoption of this new accounting standard was zero. See Note 2 for additional discussion of the early-adoption of this new accounting standard. |
OPERATING LEASES
OPERATING LEASES | 12 Months Ended |
Dec. 31, 2016 | |
Leases [Abstract] | |
OPERATING LEASES | OPERATING LEASES Vehicles The Company has from time to time leased vehicles under noncancelable operating leases. Total lease expense under the agreements was approximately $26,000 , $45,000 and $30,000 for the years ended December 31, 2016 , 2015 , and 2014 , respectively. There are no minimum future lease payments under these vehicle leases. Office Space The Company leases office space under operating leases expiring on various dates through 2021 . Minimum future annual lease payments for the calendar years presented are as follows: Amount 2017 $ 382,000 2018 342,000 2019 352,000 2020 361,000 2021 340,000 Total $ 1,777,000 The following has been recorded to rent expense for the periods presented: Years Ended December 31, 2016 2015 2014 Rent Expense $ 320,000 $ 287,000 $ 267,000 The Company’s office space lease agreements contain scheduled escalation in lease payment during the term of the lease. In accordance with GAAP, the Company records rent expense on a straight-line basis and a deferred rent liability for the difference between the straight-line amount and the actual amounts of the lease payments. Rent expense is included in the statement of operations in the “General and Administrative Expense” line item. |
FAIR VALUE
FAIR VALUE | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE | FAIR VALUE Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The Company uses a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following: Level 1 - Quoted prices in active markets for identical assets or liabilities. Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Financial Assets and Liabilities As required, financial assets and liabilities are classified in their entirety 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 requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015 . Fair Value Measurements at Quoted Prices In Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity Derivatives – Current Assets (crude oil swaps) $ — $ 4,517 $ — Commodity Derivatives – Current Liabilities (crude oil swaps and collars) — (10,001,564 ) — Commodity Derivatives – Non-Current Liabilities (crude oil swaps) — (1,738,329 ) — Total $ — $ (11,735,376 ) $ — Fair Value Measurements at Quoted Prices In Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity Derivatives – Current Assets (crude oil swaps) $ — $ 64,611,558 $ — Commodity Derivatives – Current Liabilities (crude oil swaps) — — — Commodity Derivatives – Non-Current Assets (crude oil swaps) — — — Commodity Derivatives – Non-Current Liabilities (crude oil swaps) — — — Total $ — $ 64,611,558 $ — The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include crude oil swaps, collars, and swaptions (see Note 13). The fair value of the Company’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company’s and the counterparties’ nonperformance risk is evaluated. The fair value of all derivative contracts is reflected on the balance sheet. The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months. Fair Value of Other Financial Instruments The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The carrying amount of the Company’s long-term debt reported in the balance sheet at December 31, 2016 is $832.6 million , which includes $688.6 million of senior unsecured notes including a net discount of $1.7 million and $144.0 million of borrowings under the Company’s revolving credit facility (see Note 4). The fair value of the Company’s senior unsecured notes, which are publicly traded, is $589.0 million at December 31, 2016 . The Company’s revolving credit facility approximates its fair value because of its floating rate structure. Non-Financial Assets and Liabilities The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC 410. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligations liability is deemed to use Level 3 inputs. Asset retirement obligations incurred for the year ended December 31, 2016 were approximately $0.6 million . Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. There were no transfers of financial assets or liabilities between Level 1, Level 2 or Level 3 inputs for the years ended December 31, 2016 and 2015 . |
DERIVATIVE INSTRUMENTS AND PRIC
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT | DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT The Company utilizes commodity swap contracts, swaptions and collars (purchased put options and written call options) to (i) reduce the effects of volatility in price changes on the crude oil commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending. All derivative instruments are recorded on the Company’s balance sheet as either assets or liabilities measured at their fair value (see Note 12). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value are recognized in the revenues section of the Company’s statements of operations as a gain or loss on derivative instruments. Mark-to-market gains and losses represent changes in fair values of derivatives that have not been settled. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period-end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured or were liquidated during the period. Years Ended 2016 2015 2014 Cash Received (Paid) on Derivatives (1) $ 61,528,201 $ 161,098,510 $ (7,863,104 ) Non-Cash Gain (Loss) on Derivatives (76,346,935 ) (88,715,603 ) 171,275,719 Gain (Loss) on Derivative Instruments, Net $ (14,818,734 ) $ 72,382,907 $ 163,412,615 _____________ (1) Net cash receipts for crude oil collars for the year ended December 31, 2015 include approximately $202,000 of proceeds received from crude oil derivative contracts that were settled in the second quarter of 2015 prior to their contractual maturities. The Company has master netting agreements on individual crude oil contracts with certain counterparties and therefore the current asset and liability are netted on the balance sheet and the non-current asset and liability are netted on the balance sheet for contracts with these counterparties. The following table reflects open commodity swap contracts as of December 31, 2016 , the associated volumes and the corresponding fixed price. Settlement Period Oil (Barrels) Fixed Price ($) Swaps-Crude Oil 01/01/17 – 06/30/17 360,000 50.00 01/01/17 – 06/30/17 180,000 50.01 01/01/17 – 06/30/17 180,000 49.99 01/01/17 – 06/30/17 (1) 60,000 55.20 01/01/17 – 12/31/17 360,000 54.20 01/01/17 – 12/31/17 240,000 53.25 01/01/17 – 12/31/17 365,000 54.10 07/01/17 – 12/31/17 240,000 52.75 07/01/17 – 12/31/17 120,000 52.75 07/01/17 – 12/31/17 120,000 53.50 07/01/17 – 12/31/17 60,000 54.60 07/01/17 – 12/31/17 120,000 51.75 07/01/17 – 12/31/17 120,000 53.75 01/01/18 – 9/30/18 270,000 54.00 01/01/18 – 9/30/18 270,000 54.00 01/01/18 – 9/30/18 273,000 55.20 ________________ (1) The Company has entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for an additional six-month period. Options covering a notional volume of 10,000 barrels per month are exercisable on or about June 30, 2017. If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts would increase by 10,000 barrels per month at an average price of $55.20 per barrel for each month during the period July 1, 2017 through December 31, 2017. As of December 31, 2016 , the Company had a total volume on open commodity swaps of 3.3 million barrels at a weighted average price of approximately $53.00 per barrel. The following table reflects the weighted average price of open commodity swap derivative contracts as of December 31, 2016 , by year with associated volumes. Weighted Average Price Year Volumes (Bbl) Weighted 2017 2,525,000 52.55 2018 813,000 54.40 In addition to the open commodity swap contracts the Company has entered into costless collars. The costless collars are used to establish floor and ceiling prices on anticipated crude oil production. There were no premiums paid or received by the Company related to the costless collar agreements. The following table reflects open costless collar agreements as of December 31, 2016 . Settlement Period Oil (Barrels) Floor/Ceiling Price ($) Basis 01/01/17 – 12/31/17 180,000 $50.00/$60.00 NYMEX 01/01/17 – 12/31/17 120,000 $50.00/$60.15 NYMEX The Company determines the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Company also performs an internal valuation to ensure the reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by ailing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. For further details regarding the Company’s derivative contracts see Note 12, Fair Value in the Notes to the Financial Statements. The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at December 31, 2016 and 2015 , respectively. Certain amounts may be presented on a net basis on the financial statements when such amounts are with the same counterparty and subject to a master netting arrangement: December 31, Type of Crude Oil Contract Balance Sheet Location 2016 2015 Derivative Assets: Swap Contracts Current Assets $ 4,517 $ 64,611,558 Total Derivative Assets $ 4,517 $ 64,611,558 Derivative Liabilities: Swap Contracts Current Assets/Liabilities $ (9,512,724 ) $ — Swap Contracts Non-Current Liabilities (1,738,329 ) — Swaption Contracts Current Liabilities (333,046 ) — Costless Collars Current Liabilities (155,794 ) — Total Derivative Liabilities $ (11,739,893 ) $ — The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. When the Company has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments these assets and liabilities are netted on the balance sheet. The tables presented below provide reconciliation between the gross assets and liabilities and the amounts reflected on the balance sheet. The amounts presented exclude derivative settlement receivables and payables as of the balance sheet dates. Estimated Fair Value at December 31, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Net Amounts of Assets Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ 20,962 $ (16,445 ) $ 4,517 Non-Current Assets — — — Total Derivative Assets $ 20,962 $ (16,445 ) $ 4,517 Offsetting of Derivative Liabilities: Current Liabilities $ (10,018,009 ) $ 16,445 $ (10,001,564 ) Non-Current Liabilities (1,738,329 ) — (1,738,329 ) Total Derivative Liabilities $ (11,756,338 ) $ 16,445 $ (11,739,893 ) Estimated Fair Value at December 31, 2015 Gross Amounts of Recognized Assets Gross Amounts Offset in the Net Amounts of Assets Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ 64,611,558 $ — $ 64,611,558 Non-Current Assets — — — Total Derivative Assets $ 64,611,558 $ — $ 64,611,558 Offsetting of Derivative Liabilities: Current Liabilities $ — $ — $ — Non-Current Liabilities — — — Total Derivative Liabilities $ — $ — $ — All of the Company’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDAs”) entered into with counterparties that are also lenders under the Company’s Revolving Credit Facility. The Company’s obligations under the derivative instruments are secured pursuant to the Revolving Credit Facility, and no additional collateral had been posted by the Company as of December 31, 2016 . The ISDAs may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. See Note 12 for the aggregate fair value of all derivative instruments that were in a net liability position at December 31, 2016 and 2015 . |
EARNINGS PER SHARE
EARNINGS PER SHARE | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE | EARNINGS PER SHARE The following is a reconciliation of the numerator and denominator used to calculate basic earnings per share and diluted earnings per share for the years ended December 31, 2016 , 2015 , and 2014 : 2016 2015 2014 Net Loss Shares Per Share Net Loss Shares Per Share Net Income Shares Per Share Basic EPS $ (293,493,708 ) 61,173,547 $ (4.80 ) $ (975,354,541 ) 60,652,447 $ (16.08 ) $ 163,745,945 60,691,701 $ 2.70 Dilutive Effect of Options — — — — — — — 169,068 (0.01 ) Diluted EPS $ (293,493,708 ) 61,173,547 $ (4.80 ) $ (975,354,541 ) 60,652,447 $ (16.08 ) $ 163,745,945 60,860,769 $ 2.69 For the year ended December 31, 2016 , 2015 and 2014 restricted stock of 829,313 , 322,393 , and 15,590 shares of common stock were excluded from EPS due to the anti-dilutive effect, respectively. |
RESTRUCTURING COSTS
RESTRUCTURING COSTS | 12 Months Ended |
Dec. 31, 2016 | |
Restructuring and Related Activities [Abstract] | |
RESTRUCTURING COSTS | RESTRUCTURING COSTS In September 2015, the Company restructured certain of its operations in response to the current oil and gas commodity environment. These changes, which included a reduction in workforce, are expected to result in better utilization of the Company’s resources and improved cost efficiencies. As of December 31, 2016 , there were no unpaid restructuring costs. Type of Restructuring Cost Location in the Statement of Operations Year Ended December 31, 2015 Severance and Benefit Costs Operating Expenses – General and Administrative $ 523,487 The following table summarizes the Company’s restructuring costs: Restructuring Liability at January 1, 2016 $ 32,493 Additions — Settlements (32,493 ) Revisions — Restructuring Liability at December 31, 2016 $ — |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 12 Months Ended |
Dec. 31, 2016 | |
Compensation Related Costs [Abstract] | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS In 2009, the Company adopted a defined contribution 401(k) plan for substantially all of its employees. The plan provides for Company matching of employee contributions to the plan. During 2016 , 2015 and 2014 , the Company provided a match contribution equal to 100% of an eligible employee’s deferral contribution, up to 8% of the employee’s earnings up to the maximum allowable amount. The Company contributed approximately $238,000 , $279,000 and $269,000 to the 401(k) plan for the years ended December 31, 2016 , 2015 and 2014 , respectively. |
SUPPLEMENTAL OIL AND GAS INFORM
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) | 12 Months Ended |
Dec. 31, 2016 | |
Extractive Industries [Abstract] | |
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) | CRUDE OIL AND NATURAL GAS PROPERTIES The value of the Company’s crude oil and natural gas properties consists of all acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets based on their estimated fair value at the time of the acquisition. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. Development capital expenditures and purchases of properties that were in accounts payable and not yet paid in cash at December 31, 2016 and 2015 were approximately $50.7 million and $59.5 million , respectively. 2016 Acquisitions During 2016 , the Company acquired approximately 3,399 net acres, for an average cost of approximately $1,515 per net acre, in its key prospect areas in the form of effective leases. On October 6, 2016, the Company entered into a definitive purchase and sale agreement with a third party, for their interests in 144 gross ( 3.8 net) producing oil and gas wells and associated acreage. The motivation for the acquisition was the expectation that it was accretive to cash flow and earnings per share. On October 26, 2016, the Company closed the transaction for cash consideration of $9.4 million which is comprised of $8.9 million related to producing properties and a $0.5 million reimbursement of drilling costs on in process wells. The results of operations from the October 26, 2016 closing date through December 31, 2016 , represented approximately $1.2 million of revenue and $0.5 million of direct operating expenses. The combined pro forma information has not been presented due to its immateriality. No material transaction costs were incurred in connection with this purchase and there was no goodwill recorded from this acquisition. 2015 Acquisitions During 2015 , the Company acquired approximately 4,355 net acres, for an average cost of approximately $1,314 per net acre, in its key prospect areas in the form of effective leases. 2014 Acquisitions During 2014 , the Company acquired approximately 22,668 net acres, for an average cost of approximately $1,534 per net acre, in its key prospect areas in the form of effective leases. Divestitures From time-to-time the Company may divest assets. In addition, the Company may trade leasehold interests with operators to balance working interests in spacing units to facilitate and encourage a more expedited development of the Company’s acreage. Unproved Properties Unproved properties not being amortized comprise approximately 26,432 net acres and 38,003 net acres of undeveloped leasehold interests at December 31, 2016 and 2015 , respectively. The Company believes that the majority of its unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves. Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years . The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2016 by year incurred. Years Ended December 31, 2016 2015 2014 Prior Years Property Acquisition $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 Development — — — — Total $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion. Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion. The Company historically has acquired its properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. The Company generally participates in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling. The Company assesses all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization. For the years ended December 31, 2016 , 2015 and 2014 , the Company included $7.0 million , $37.6 million and $21.4 million , respectively, related to expiring leases within costs subject to the depletion calculation. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil and Natural Gas Exploration and Production Activities Oil and gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of crude oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company’s crude oil and natural gas production activities are provided in the Company’s related statements of income. Costs Incurred and Capitalized Costs The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below. Years Ended December 31, 2016 2015 2014 Costs Incurred for the Year: Proved Property Acquisition and Other $ 18,531,518 $ 9,068,139 $ 29,838,482 Unproved Property Acquisition 2,301,285 3,346,214 27,561,901 Development 63,621,429 116,255,535 479,472,251 Total $ 84,454,232 $ 128,669,888 $ 536,872,634 Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2016 by year incurred. Years Ended December 31, 2016 2015 2014 Prior Years Property Acquisition $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 Development — — — — Total $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 Oil and Natural Gas Reserves and Related Financial Data Information with respect to the Company’s crude oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Ryder Scott Company, independent petroleum consultants based on information provided by the Company. Oil and Natural Gas Reserve Data The following tables present the Company’s independent petroleum consultants’ estimates of its proved crude oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Natural Gas Oil BOE Proved Developed and Undeveloped Reserves at December 31, 2013 50,168,133 75,799,125 84,160,481 Revisions of Previous Estimates 2,465,251 (11,397,088 ) (10,986,213 ) Extensions, Discoveries and Other Additions 21,984,514 29,662,181 33,326,267 Production (3,682,781 ) (5,150,913 ) (5,764,710 ) Proved Developed and Undeveloped Reserves at December 31, 2014 70,935,117 88,913,305 100,735,825 Revisions of Previous Estimates (23,552,809 ) (36,277,018 ) (40,202,486 ) Extensions, Discoveries and Other Additions 8,170,259 9,346,864 10,708,574 Production (4,651,583 ) (5,168,687 ) (5,943,951 ) Proved Developed and Undeveloped Reserves at December 31, 2015 50,900,984 56,814,464 65,297,962 Revisions of Previous Estimates (8,697,825 ) (13,995,801 ) (15,445,439 ) Extensions, Discoveries and Other Additions 7,695,309 7,142,439 8,424,991 Purchases of Minerals in Place 960,758 640,108 800,234 Production (4,026,899 ) (4,325,919 ) (4,997,069 ) Proved Developed and Undeveloped Reserves at December 31, 2016 46,832,327 46,275,291 54,080,679 Proved Developed Reserves: December 31, 2013 20,642,967 32,043,405 35,483,900 December 31, 2014 38,277,770 44,666,408 51,046,037 December 31, 2015 33,619,954 36,573,821 42,177,147 December 31, 2016 32,808,111 32,245,139 37,713,158 Proved Undeveloped Reserves: December 31, 2013 29,525,166 43,755,720 48,676,581 December 31, 2014 32,657,347 44,246,897 49,689,788 December 31, 2015 17,281,030 20,240,643 23,120,815 December 31, 2016 14,024,216 14,030,152 16,367,521 Proved reserves are estimated quantities of crude oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years. Notable changes in proved reserves for the year ended December 31, 2016 included the following: • Extensions and discoveries . In 2016 , total extensions and discoveries of 8.4 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in these areas as well as the proved undeveloped locations added as a result of drilling increased the Company’s proved reserves. • Purchases of minerals in place . In 2016 , total purchases of minerals in place of 0.8 MMBOE were primarily attributable to an acquisition with a third party (See Note 3). • Revisions to previous estimates . In 2016 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 15.4 MMBOE. Included in these revisions were 15.7 MMBOE of downward adjustments caused by lower crude oil and natural gas prices and 3.4 MMBOE of downward adjustments related to the removal of undeveloped drilling locations related to the 5 year rule which was partially offset by a 3.6 MMBOE upward adjustment attributable to well performance when comparing the Company’s reserve estimates at December 31, 2016 to December 31, 2015 . Notable changes in proved reserves for the year ended December 31, 2015 included the following: • Extensions and discoveries . In 2015 , total extensions and discoveries of 10.7 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in these areas as well as the proved undeveloped locations added as a result of drilling increased the Company’s proved reserves. • Revisions to previous estimates . In 2015 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 40.2 MMBOE. Included in these revisions were 52.6 MMBOE of downward adjustments caused by lower crude oil and natural gas prices and 12.4 MMBOE of net upward adjustments attributable to reservoir analysis and well performance when comparing the Company’s reserve estimates at December 31, 2015 to December 31, 2014. Notable changes in proved reserves for the year ended December 31, 2014 included the following: • Extensions and discoveries . In 2014 , total extensions and discoveries of 33.3 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in these areas as well as the proved undeveloped locations added as a result of drilling increased the Company’s proved reserves. • Revisions to previous estimates . In 2014 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 11.0 MMBOE. Included in these revisions were 0.9 MMBOE of net upward adjustments attributable to well performance and 2.1 MMBOE of downward adjustments caused by lower crude oil prices and 9.8 MMBOE downward adjustments attributable to reservoir analysis when comparing the Company’s reserve estimates at December 31, 2014 to December 31, 2013. Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein The following table presents a standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating proved crude oil and natural gas were prepared in accordance with the provisions of ASC 932 Extractive Activities - Oil and Gas . Future cash inflows were computed by applying average prices of crude oil and natural gas for the last 12 months to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year end tax rates to future pretax cash flows relating to proved crude oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carry forwards relating to crude oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s crude oil and natural gas reserves. Years Ended December 31, 2016 2015 2014 Future Cash Inflows $ 1,708,870,912 $ 2,470,707,712 $ 7,912,622,500 Future Production Costs (775,534,832 ) (981,256,096 ) (2,281,320,000 ) Future Development Costs (220,869,664 ) (356,401,888 ) (1,453,562,125 ) Future Income Tax Expense (2,477,353 ) (5,740,623 ) (1,058,511,086 ) Future Net Cash Inflows $ 709,989,063 $ 1,127,309,105 $ 3,119,229,289 10% Annual Discount for Estimated Timing of Cash Flows (330,963,050 ) (552,510,342 ) (1,713,849,746 ) Standardized Measure of Discounted Future Net Cash Flows $ 379,026,013 $ 574,798,763 $ 1,405,379,543 The twelve month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The price of other liquids is included in natural gas. The prices for the Company’s reserve estimates were as follows: Natural Gas MCF Oil Bbl December 31, 2016 $ 1.67 $ 35.24 December 31, 2015 $ 1.63 $ 42.03 December 31, 2014 $ 7.37 $ 83.11 The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows. As a result of available net operating loss carryforwards and the remaining tax basis of its assets at December 31, 2016 , the Company’s future income taxes were significantly reduced. Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow: Years Ended December 31, 2016 2015 2014 Beginning of Period $ 574,798,763 $ 1,405,379,543 $ 1,224,366,826 Sales of Oil and Natural Gas Produced, Net of Production Costs (98,497,165 ) (128,964,023 ) (330,395,323 ) Extensions and Discoveries 59,542,911 96,770,078 567,026,734 Previously Estimated Development Cost Incurred During the Period 23,271,960 114,208,095 205,125,299 Net Change of Prices and Production Costs (174,656,448 ) (1,384,474,928 ) (52,577,882 ) Change in Future Development Costs 57,481,060 235,578,690 (64,185,447 ) Revisions of Quantity and Timing Estimates (130,664,183 ) (363,975,445 ) (326,674,460 ) Accretion of Discount 57,569,313 170,222,344 152,128,992 Change in Income Taxes 497,950 295,949,531 (79,196 ) Purchases of Minerals in Place 9,576,760 — — Other 105,092 134,104,878 30,644,000 End of Period $ 379,026,013 $ 574,798,763 $ 1,405,379,543 |
QUARTERLY RESULTS OF OPERATIONS
QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) | QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) Quarterly data for the years end December 31, 2016 and 2015 is as follows: Quarter Ended March 31, June 30, September 30, December 31, 2016 Total Revenues $ 31,836,236 $ 32,014,226 $ 45,109,408 $ 35,943,626 Gains (Losses) on Derivative Instruments, Net 3,463,883 (10,522,948 ) 3,381,564 (11,141,233 ) Total Operating Expenses 141,220,772 124,946,744 74,583,046 33,457,789 Impairment 104,311,122 88,880,921 43,820,791 — Income (Loss) from Operations (109,384,536 ) (92,932,518 ) (29,473,638 ) 2,485,837 Other Income (Expense) (17,181,218 ) (16,046,144 ) (16,145,257 ) (16,218,413 ) Income Tax Benefit — — — (1,402,179 ) Net Loss (126,565,754 ) (108,978,662 ) (45,618,895 ) (12,330,397 ) Net Loss Per Common Share – Basic (2.08 ) (1.78 ) (0.74 ) (0.20 ) Net Loss Per Common Share – Diluted (2.08 ) (1.78 ) (0.74 ) (0.20 ) Quarter Ended March 31, June 30, September 30, December 31, 2015 Total Revenues $ 76,124,638 $ 40,863,194 $ 101,156,552 $ 56,913,029 Gains (Losses) on Derivative Instruments, Net 25,663,283 (22,211,048 ) 51,366,762 17,563,910 Total Operating Expenses 429,607,005 343,402,927 408,323,554 213,112,194 Impairment 360,428,962 281,964,097 354,422,654 167,143,533 Loss from Operations (353,482,367 ) (302,539,733 ) (307,167,002 ) (156,199,165 ) Other Income (Expense) (11,736,205 ) (14,387,494 ) (16,152,574 ) (16,114,205 ) Income Tax Benefit (135,480,000 ) (66,866,610 ) (77,544 ) (50 ) Net Loss (229,738,572 ) (250,060,617 ) (323,242,032 ) (172,313,320 ) Net Loss Per Common Share – Basic (3.79 ) (4.12 ) (5.33 ) (2.84 ) Net Loss Per Common Share – Diluted (3.79 ) (4.12 ) (5.33 ) (2.84 ) |
SIGNIFICANT ACCOUNTING POLICI26
SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Use of Estimates | Use of Estimates The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved crude oil and natural gas reserve volumes, future development costs, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, impairment of oil and natural gas properties, and deferred income taxes. Actual results may differ from those estimates. |
Reclassifications | Reclassifications Certain prior period balances in the balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net loss, cash flows or stockholders’ deficit previously reported. |
Cash and Cash Equivalents | Cash and Cash Equivalents Northern considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than $250,000 , the Company does not have FDIC coverage on the entire amount of bank deposits. The Company believes this risk is minimal. In addition, the Company is subject to Security Investor Protection Corporation (“SIPC”) protection on a vast majority of its financial assets. |
Accounts Receivable | Accounts Receivable Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. Accounts receivable not expected to be collected within the next twelve months are included within Other Noncurrent Assets, Net on the balance sheets. |
Advances to Operators | Advances to Operators The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. |
Other Property and Equipment | Other Property and Equipment Property and equipment that are not crude oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than crude oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-crude oil and natural gas long-lived assets. |
Oil and Gas Properties | Oil and Gas Properties Northern follows the full cost method of accounting for crude oil and natural gas operations whereby all costs related to the exploration and development of crude oil and natural gas properties are capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2016 , 2015 and 2014 , respectively: Years Ended December 31, 2016 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ 1,890,480 $ 2,717,913 $ 2,153,448 Capitalized Interest Costs 356,196 1,506,172 4,409,544 Total $ 2,246,676 $ 4,224,085 $ 6,562,992 As of December 31, 2016 , the Company held leasehold interests in the Williston Basin on acreage located in North Dakota and Montana targeting the Bakken and Three Forks formations. Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. In the years ended December 31, 2016 , 2015 and 2014 , there were no property sales that resulted in a significant alteration. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing twelve-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives designated as hedges for accounting purposes, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. As a result of low commodity prices and their effect on the proved reserve values of properties, the Company recorded non-cash ceiling test impairments for the years ended December 31, 2016 and 2015 of $237.0 million , and $1.2 billion , respectively. The Company did not have any impairment of its proved oil and gas properties during 2014 . The impairment charges affected the Company’s reported net income but did not reduce the Company’s cash flow. If a significantly lower pricing environment reoccurs, we expect we could be required to further writedown the value of our oil and natural gas properties. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine the Company’s actual ceiling test calculation and impairment analyses in future periods. Capitalized costs associated with impaired properties and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized on the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations. For the years ended December 31, 2016 , 2015 and 2014 , the Company expired leases of $13.4 million , $19.0 million , and $26.3 million , respectively. |
Asset Retirement Obligations | Asset Retirement Obligations The Company accounts for its abandonment and restoration liabilities under Financial Accounting Standards Board (“FASB”) ASC Topic 410, “Asset Retirement and Environmental Obligations” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. |
Business Combinations | Business Combinations The Company accounts for its acquisitions that qualify as a business using the acquisition method under FASB ASC Topic 805, “Business Combinations.” Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain. |
Debt Issuance Costs | Debt Issuance Costs Debt issuance costs include origination, legal and other fees to issue debt in connection with the Company’s credit facility and senior unsecured notes. These debt issuance costs are being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method (see Note 4). The amortization of debt issuance costs for the years ended December 31, 2016 , 2015 and 2014 was $3.8 million , $3.7 million and $2.8 million , respectively. During the year ended December 31, 2016 , $1.1 million of debt issuance costs were written-off as a result of a reduction in the borrowing base of the Revolving Credit Facility, which became effective in May 2016 and was due to the impact that lower commodity prices had on our oil and gas reserve valuation. There were no debt issuance costs written-off during the years ended December 31, 2015 and 2014 , respectively. As a result of the adoption of ASU No. 2015-03 , “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”), the Company reclassified unamortized debt issuance costs associated with its 8% Senior Notes, which totaled $12.5 million as of December 31, 2015 , from “Debt Issuance Costs, Net” to a reduction of “Long-term Debt, Net” on the balance sheets. Adoption of ASU 2015-03 had no impact on the Company’s current and previously reported stockholders’ deficit, results of operations, or cash flows. |
Bond Premium/Discount on Senior Notes | Bond Premium/Discount on Senior Notes On May 13, 2013, the Company recorded a bond premium of $10.5 million in connection with the “ 8% Senior Notes Due 2020” (see Note 4). This bond premium is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization of the bond premium was $1.5 million for each of the years ended December 31, 2016 , 2015 and 2014 . On May 18, 2015, the Company recorded a bond discount of $10.0 million in connection with the “ 8% Senior Notes Due 2020” (see Note 4). This bond discount is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization of the bond discount for the years ended December 31, 2016 , 2015 and 2014 was $2.0 million , $1.2 million and zero , respectively. |
Revenue Recognition | Revenue Recognition The Company recognizes crude oil and natural gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2016 , 2015 and 2014 , the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells. |
Concentrations of Market and Credit Risk | Concentrations of Market and Credit Risk The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. The Company operates in the exploration, development and production sector of the crude oil and natural gas industry. The Company’s receivables include amounts due from purchasers of its crude oil and natural gas production. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its counterparties is generally high. In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk. |
Restructuring Costs | Restructuring Costs The Company accounts for restructuring costs in accordance with FASB ASC Topic 420, “Exit or Disposal Cost Obligations.” Under these standards, the costs associated with restructuring are recorded during the period in which the liability is incurred. During the year ended December 31, 2015 , the Company recognized $0.5 million in restructuring costs for employee severance and related benefit costs incurred as part of a reduction in workforce and the closing of its Denver office, which included $0.1 million of non-cash expense related to acceleration of certain equity awards previously granted under the Company’s 2013 Incentive Plan. |
Stock-Based Compensation | Stock-Based Compensation The Company records expense associated with the fair value of stock-based compensation. For fully vested stock and restricted stock grants the Company calculates the stock-based compensation expense based upon estimated fair value on the date of grant. In determining the fair value of performance-based share awards, the Company utilizes a Monte Carlo simulation prepared by an independent third party. For stock options, the Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate. |
Stock Issuance | Stock Issuance The Company records any stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable. |
Income Taxes | Income Taxes The Company’s income tax expense, deferred tax assets and deferred tax liabilities reflect management’s best assessment of estimated current and future taxes to be paid. The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The Company’s only taxing jurisdiction is the United States (federal and state). Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future. In evaluating the Company’s ability to recover its deferred tax assets, the Company considers all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, the Company begins with historical results and incorporates assumptions about the amount of future state and federal pretax operating income adjusted for items that do not have tax consequences. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. In assessing the need for a valuation allowance for the Company’s deferred tax assets, a significant item of negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2016 , driven primarily by the full cost ceiling impairments over that period. Additionally, the Company’s revenue, profitability and future growth are substantially dependent upon prevailing and future prices for oil and natural gas. The markets for these commodities continue to be volatile. Changes in oil and natural gas prices have a significant impact on the value of the Company’s reserves and on its cash flows. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond the Company’s control. Due to these factors, management has placed a lower weight on the prospect of future earnings in its overall analysis of the valuation allowance. In determining whether to establish a valuation allowance on the Company’s deferred tax assets, management concluded that the objectively verifiable evidence of cumulative negative earnings for the three-year period ended December 31, 2016 , is difficult to overcome with any forms of positive evidence that may exist. |
Net Income Per Common Share | Net Income Per Common Share Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options and restricted stock. The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method. |
Derivative Instruments and Price Risk Management | Derivative Instruments and Price Risk Management The Company uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil. The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date. The Company follows the provisions of FASB ASC 815, “Derivatives and Hedging” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value and marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations. See Note 13 for a description of the derivative contracts into which the Company has entered. |
Impairment | Impairment Long-lived assets to be held and used are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Crude oil and natural gas properties accounted for using the full cost method of accounting are excluded from this requirement but continue to be subject to the full cost method’s impairment rules. |
New Accounting Pronouncements | New Accounting Pronouncements From time to time, new accounting pronouncements are issued by the FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers . The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in United States GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers – Deferral of the Effective Date,” which approved a one year deferral of ASU 2014-09 for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early application is permitted as of the original effective date for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company will adopt this ASU on January 1, 2018. The Company is evaluating the impact of this ASU on our financial statements and, based on the continuing evaluation of our revenue streams, this ASU is not expected to have a material impact on our financial statements. The Company expects it will use the modified retrospective approach to implementation. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The standard requires lessees to recognize the assets and liabilities that arise from leases on the balance sheet. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The new guidance is effective for annual and interim reporting periods beginning after December 15, 2018. The amendments should be applied at the beginning of the earliest period presented using a modified retrospective approach with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact of the new guidance on our financial statements, however, based on our current operating leases, it is not expected to have a material impact. In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting , which relates to the accounting for employee share-based payments. This standard addresses several aspects of the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company elected to early-adopt this guidance in the fourth quarter of 2016 utilizing the adoption methods required by the ASU. The Company will continue its current accounting policy for forfeitures. See Note 10 for discussion of additional accounting consequences related to the adoption of this ASU. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This guidance rescinds SEC Staff Observer comments that are codified in Topic 606, Revenue Recognition, and Topic 932, Extractive Activities--Oil and Gas. This amendment is effective upon adoption of Topic 606. The Company is in the process of evaluating the impact of this guidance on our financial statements. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments . This guidance provides guidance of eight specific cash flow issues. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on our financial statements. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. This guidance updates narrow aspects of the guidance issued in Update 2014-09. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this ASU on our financial statements. |
SIGNIFICANT ACCOUNTING POLICI27
SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Capitalized costs related to the exploration and development of crude oil and natural gas properties | Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2016 , 2015 and 2014 , respectively: Years Ended December 31, 2016 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ 1,890,480 $ 2,717,913 $ 2,153,448 Capitalized Interest Costs 356,196 1,506,172 4,409,544 Total $ 2,246,676 $ 4,224,085 $ 6,562,992 The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below. Years Ended December 31, 2016 2015 2014 Costs Incurred for the Year: Proved Property Acquisition and Other $ 18,531,518 $ 9,068,139 $ 29,838,482 Unproved Property Acquisition 2,301,285 3,346,214 27,561,901 Development 63,621,429 116,255,535 479,472,251 Total $ 84,454,232 $ 128,669,888 $ 536,872,634 |
Defined prices for each quarter | SEC defined prices for each quarter-end in 2016 were as follows: SEC Defined Prices for 12-Months Ended NYMEX Oil Price (per Bbl) Henry Hub Gas Price (per MMBtu) December 31, 2016 $ 42.75 $ 2.49 September 30, 2016 41.68 2.28 June 30, 2016 43.12 2.24 March 31, 2016 46.26 2.39 The twelve month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The price of other liquids is included in natural gas. The prices for the Company’s reserve estimates were as follows: Natural Gas MCF Oil Bbl December 31, 2016 $ 1.67 $ 35.24 December 31, 2015 $ 1.63 $ 42.03 December 31, 2014 $ 7.37 $ 83.11 |
Reconciliation of denominators used to calculate basic and diluted EPS | The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the years ended December 31, 2016 , 2015 and 2014 are as follows: Years Ended December 31, 2016 2015 2014 Weighted Average Common Shares Outstanding – Basic 61,173,547 60,652,447 60,691,701 Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock — — 169,068 Weighted Average Common Shares Outstanding – Diluted 61,173,547 60,652,447 60,860,769 Restricted Stock and Stock Options Excluded From EPS Due To The Anti-Dilutive Effect 829,313 322,393 15,590 |
CRUDE OIL AND NATURAL GAS PRO28
CRUDE OIL AND NATURAL GAS PROPERTIES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Summary of capitalized costs excluded from depletion | The following is a summary of capitalized costs excluded from depletion at December 31, 2016 by year incurred. Years Ended December 31, 2016 2015 2014 Prior Years Property Acquisition $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 Development — — — — Total $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 |
LONG TERM DEBT (Tables)
LONG TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of long term debt | The Company’s long-term debt consists of the following: December 31, 2016 Long-term Debt Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 698,306,153 $ (9,681,028 ) $ 688,625,125 Revolving Credit Facility (1) 144,000,000 — 144,000,000 Total $ 842,306,153 $ (9,681,028 ) $ 832,625,125 December 31, 2015 Long-term Debt Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 697,804,829 $ (12,514,500 ) $ 685,290,329 Revolving Credit Facility (1) 150,000,000 — 150,000,000 Total $ 847,804,829 $ (12,514,500 ) $ 835,290,329 _____________ (1) Debt issuance costs related to our revolving credit facility are recorded in “Other Noncurrent Assets, Net” on the balance sheets |
Schedule of debt covenants | The schedule of the minimum ratio of EBITDAX to interest expense the Company is required to maintain is as follows: Measurement Period Minimum ratio of EBITDAX to Interest Expense 12 months ending December 31, 2016 1.75 to 1.00 12 months ending March 31, 2017 1.50 to 1.00 12 months ending June 30, 2017 1.25 to 1.00 12 months ending September 30, 2017 1.25 to 1.00 12 months ending December 31, 2017 1.00 to 1.00 12 months ending March 31, 2018 1.00 to 1.00 12 months ending June 30, 2018 and beyond 2.50 to 1.00 |
COMMON AND PREFERRED STOCK (Tab
COMMON AND PREFERRED STOCK (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
Schedule of changes in the number of common stock shares | The following is a schedule of changes in the number of shares of common stock outstanding since the beginning of 2014 : Years Ended December 31, 2016 2015 2014 Beginning Balance 63,120,384 61,066,712 61,858,199 Stock Options Exercised — — 100,000 Restricted Stock Grants (Note 6) 2,109,814 2,112,998 299,416 Stock Repurchased — — (1,153,885 ) Other Surrenders (375,875 ) (57,929 ) (79,461 ) Other (1,594,542 ) (1,397 ) 42,443 Ending Balance 63,259,781 63,120,384 61,066,712 |
STOCK OPTIONS_STOCK-BASED COM31
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Restricted stock activity | The following table reflects the outstanding restricted stock awards and activity related thereto for the years ended December 31, 2016 , 2015 and 2014 : Year Ended Year Ended Year Ended Number of Shares Weighted- Average Price Number Of Shares Weighted- Average Price Number Of Shares Weighted- Average Price Restricted Stock Awards: Restricted Shares Outstanding at the Beginning of the Year 2,365,396 $ 7.15 538,499 $ 13.54 592,565 $ 16.84 Shares Granted 2,109,814 3.83 2,112,998 6.29 299,416 12.09 Shares Forfeited (1,594,542 ) 4.67 (1,397 ) 14.79 — — Lapse of Restrictions (975,564 ) 7.34 (284,704 ) 12.24 (353,482 ) 17.84 Restricted Shares Outstanding at the End of the Year 1,905,104 $ 4.59 2,365,396 $ 7.15 538,499 $ 13.54 |
Stock option activity | Changes in stock option awards for the years ended December 31, 2016 , 2015 , and 2014 were as follows: Stock Option Awards Weighted-Average Price Weighted Average Contractual Term Intrinsic Value Outstanding as of December 31, 2013 (1) 241,872 $ 5.18 3.8 $ 2,392,000 Granted — — Exercised (100,000 ) 5.18 Expired or canceled — — Forfeited — — Outstanding as of December 31, 2014 (1) 141,872 5.18 2.8 $ 66,680 Granted — — Exercised — — Expired or canceled — — Forfeited — — Outstanding as of December 31, 2015 (1) 141,872 5.18 1.8 $ — Granted 250,000 2.79 Exercised — — Expired or canceled — — Forfeited — — Outstanding as of December 31, 2016 (1) 391,872 $ 3.66 2.9 $ — ____________ (1) All of the stock options outstanding were vested and exercisable at the end of the period. |
Valuation Assumptions | The assumptions used to estimate the fair value of stock option awards granted in February, 2016 are as follows: February 12, 2016 Risk-free interest rate 1.15 % Expected life 5.0 Expected volatility 61.89 % Fair value per option: $ 1.47 |
ASSET RETIREMENT OBLIGATION (Ta
ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation [Abstract] | |
Asset retirement obligation transactions | The following table summarizes the Company’s asset retirement obligation transactions recorded during the year ended December 31, 2016 and 2015 . Years Ended December 31, 2016 2015 Beginning Asset Retirement Obligation $ 5,816,356 $ 5,105,762 Liabilities Acquired or Incurred During the Period 585,729 475,306 Liabilities Removed Due to Divestitures (21,426 ) — Revision of Estimates 789,003 (53,912 ) Accretion of Discount on Asset Retirement Obligations 405,991 372,461 Liabilities Settled During the Period (67,353 ) (83,261 ) Ending Asset Retirement Obligation $ 7,508,300 $ 5,816,356 |
(Tables)
(Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income tax expense provision (benefit) | The income tax provision (benefit) for the year ended December 31, 2016 , 2015 , and 2014 consists of the following: 2016 2015 2014 Current $ (1,402,179 ) $ (73,649 ) $ 3,259,445 Deferred Federal (99,298,900 ) (398,002,555 ) 87,625,430 State (9,707,000 ) (36,608,000 ) 8,482,125 Valuation Allowance 109,005,900 232,260,000 — Total Expense (Benefit) $ (1,402,179 ) $ (202,424,204 ) $ 99,367,000 |
Reconciliation of reported amount of income tax expense (benefit) | The following is a reconciliation of the reported amount of income tax expense for the years ended December 31, 2016 , 2015 , and 2014 to the amount of income tax expenses that would result from applying the statutory rate to pretax income. 2016 2015 2014 Income (Loss) Before Taxes and NOL $ (294,895,887 ) $ (1,177,778,745 ) $ 263,112,945 Federal Statutory Rate 35.00 % 35.00 % 35.00 % Taxes Computed at Federal Statutory Rates (103,214,000 ) (412,223,000 ) 92,090,000 State Taxes, Net of Federal Taxes (6,306,000 ) (23,825,000 ) 5,404,300 Non-Deductible Compensation 82,000 470,000 456,000 Share Based Compensation Tax Deficiency (834,900 ) 307,000 1,472,000 Other (135,179 ) 586,796 (55,300 ) Valuation Allowance 109,005,900 232,260,000 — Reported Provision (Benefit) $ (1,402,179 ) $ (202,424,204 ) $ 99,367,000 |
Components of deferred tax asset (liability) | The significant components of the Company’s deferred tax assets (liabilities) were as follows: Years Ended December 31, 2016 2015 Net Operating Loss (NOLs) and Tax Credit Carryforwards $ 224,679,900 $ 195,207,000 Share Based Compensation 1,032,000 1,762,000 Accrued Interest 1,727,000 1,723,000 Allowance for Doubtful Accounts 1,795,000 1,662,000 Crude Oil and Natural Gas Properties and Other Properties 107,642,000 55,939,000 Derivative Instruments 4,341,000 (23,855,000 ) Other 49,000 (178,000 ) Total Net Deferred Tax Assets (Liabilities) Before Valuation Allowance 341,265,900 232,260,000 Valuation Allowance (341,265,900 ) (232,260,000 ) Total Net Deferred Tax Assets (Liabilities) $ — $ — |
OPERATING LEASES (Tables)
OPERATING LEASES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Leases [Abstract] | |
Minimum future lease payments | Minimum future annual lease payments for the calendar years presented are as follows: Amount 2017 $ 382,000 2018 342,000 2019 352,000 2020 361,000 2021 340,000 Total $ 1,777,000 |
FAIR VALUE (Tables)
FAIR VALUE (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Financial instruments measured at fair value on recurring basis | The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015 . Fair Value Measurements at Quoted Prices In Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity Derivatives – Current Assets (crude oil swaps) $ — $ 4,517 $ — Commodity Derivatives – Current Liabilities (crude oil swaps and collars) — (10,001,564 ) — Commodity Derivatives – Non-Current Liabilities (crude oil swaps) — (1,738,329 ) — Total $ — $ (11,735,376 ) $ — Fair Value Measurements at Quoted Prices In Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity Derivatives – Current Assets (crude oil swaps) $ — $ 64,611,558 $ — Commodity Derivatives – Current Liabilities (crude oil swaps) — — — Commodity Derivatives – Non-Current Assets (crude oil swaps) — — — Commodity Derivatives – Non-Current Liabilities (crude oil swaps) — — — Total $ — $ 64,611,558 $ — |
DERIVATIVE INSTRUMENTS AND PR36
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of non-cash gains or losses on derivative contracts | The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period-end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured or were liquidated during the period. Years Ended 2016 2015 2014 Cash Received (Paid) on Derivatives (1) $ 61,528,201 $ 161,098,510 $ (7,863,104 ) Non-Cash Gain (Loss) on Derivatives (76,346,935 ) (88,715,603 ) 171,275,719 Gain (Loss) on Derivative Instruments, Net $ (14,818,734 ) $ 72,382,907 $ 163,412,615 _____________ (1) Net cash receipts for crude oil collars for the year ended December 31, 2015 include approximately $202,000 of proceeds received from crude oil derivative contracts that were settled in the second quarter of 2015 prior to their contractual maturities. |
Open commodity swap contracts | The following table reflects open commodity swap contracts as of December 31, 2016 , the associated volumes and the corresponding fixed price. Settlement Period Oil (Barrels) Fixed Price ($) Swaps-Crude Oil 01/01/17 – 06/30/17 360,000 50.00 01/01/17 – 06/30/17 180,000 50.01 01/01/17 – 06/30/17 180,000 49.99 01/01/17 – 06/30/17 (1) 60,000 55.20 01/01/17 – 12/31/17 360,000 54.20 01/01/17 – 12/31/17 240,000 53.25 01/01/17 – 12/31/17 365,000 54.10 07/01/17 – 12/31/17 240,000 52.75 07/01/17 – 12/31/17 120,000 52.75 07/01/17 – 12/31/17 120,000 53.50 07/01/17 – 12/31/17 60,000 54.60 07/01/17 – 12/31/17 120,000 51.75 07/01/17 – 12/31/17 120,000 53.75 01/01/18 – 9/30/18 270,000 54.00 01/01/18 – 9/30/18 270,000 54.00 01/01/18 – 9/30/18 273,000 55.20 ________________ (1) The Company has entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for an additional six-month period. Options covering a notional volume of 10,000 barrels per month are exercisable on or about June 30, 2017. If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts would increase by 10,000 barrels per month at an average price of $55.20 per barrel for each month during the period July 1, 2017 through December 31, 2017. The following table reflects open costless collar agreements as of December 31, 2016 . Settlement Period Oil (Barrels) Floor/Ceiling Price ($) Basis 01/01/17 – 12/31/17 180,000 $50.00/$60.00 NYMEX 01/01/17 – 12/31/17 120,000 $50.00/$60.15 NYMEX |
Schedule of weighted average price of open commodity derivative contracts | The following table reflects the weighted average price of open commodity swap derivative contracts as of December 31, 2016 , by year with associated volumes. Weighted Average Price Year Volumes (Bbl) Weighted 2017 2,525,000 52.55 2018 813,000 54.40 |
Derivatives instruments balance sheet location | The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at December 31, 2016 and 2015 , respectively. Certain amounts may be presented on a net basis on the financial statements when such amounts are with the same counterparty and subject to a master netting arrangement: December 31, Type of Crude Oil Contract Balance Sheet Location 2016 2015 Derivative Assets: Swap Contracts Current Assets $ 4,517 $ 64,611,558 Total Derivative Assets $ 4,517 $ 64,611,558 Derivative Liabilities: Swap Contracts Current Assets/Liabilities $ (9,512,724 ) $ — Swap Contracts Non-Current Liabilities (1,738,329 ) — Swaption Contracts Current Liabilities (333,046 ) — Costless Collars Current Liabilities (155,794 ) — Total Derivative Liabilities $ (11,739,893 ) $ — |
Reconciliation between gross assets and liabilities and the amounts reflected on balance sheet | The tables presented below provide reconciliation between the gross assets and liabilities and the amounts reflected on the balance sheet. The amounts presented exclude derivative settlement receivables and payables as of the balance sheet dates. Estimated Fair Value at December 31, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Net Amounts of Assets Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ 20,962 $ (16,445 ) $ 4,517 Non-Current Assets — — — Total Derivative Assets $ 20,962 $ (16,445 ) $ 4,517 Offsetting of Derivative Liabilities: Current Liabilities $ (10,018,009 ) $ 16,445 $ (10,001,564 ) Non-Current Liabilities (1,738,329 ) — (1,738,329 ) Total Derivative Liabilities $ (11,756,338 ) $ 16,445 $ (11,739,893 ) Estimated Fair Value at December 31, 2015 Gross Amounts of Recognized Assets Gross Amounts Offset in the Net Amounts of Assets Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ 64,611,558 $ — $ 64,611,558 Non-Current Assets — — — Total Derivative Assets $ 64,611,558 $ — $ 64,611,558 Offsetting of Derivative Liabilities: Current Liabilities $ — $ — $ — Non-Current Liabilities — — — Total Derivative Liabilities $ — $ — $ — |
EARNINGS PER SHARE (Tables)
EARNINGS PER SHARE (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Calculation of earnings per share | The following is a reconciliation of the numerator and denominator used to calculate basic earnings per share and diluted earnings per share for the years ended December 31, 2016 , 2015 , and 2014 : 2016 2015 2014 Net Loss Shares Per Share Net Loss Shares Per Share Net Income Shares Per Share Basic EPS $ (293,493,708 ) 61,173,547 $ (4.80 ) $ (975,354,541 ) 60,652,447 $ (16.08 ) $ 163,745,945 60,691,701 $ 2.70 Dilutive Effect of Options — — — — — — — 169,068 (0.01 ) Diluted EPS $ (293,493,708 ) 61,173,547 $ (4.80 ) $ (975,354,541 ) 60,652,447 $ (16.08 ) $ 163,745,945 60,860,769 $ 2.69 |
RESTRUCTURING COSTS (Tables)
RESTRUCTURING COSTS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Restructuring and Related Activities [Abstract] | |
Restructuring related costs | Type of Restructuring Cost Location in the Statement of Operations Year Ended December 31, 2015 Severance and Benefit Costs Operating Expenses – General and Administrative $ 523,487 |
Schedule of restructuring costs | The following table summarizes the Company’s restructuring costs: Restructuring Liability at January 1, 2016 $ 32,493 Additions — Settlements (32,493 ) Revisions — Restructuring Liability at December 31, 2016 $ — |
SUPPLEMENTAL OIL AND GAS INFO39
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Extractive Industries [Abstract] | |
Schedule of costs incurred in crude oil and natural gas acquisition, exploration and development activities | Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2016 , 2015 and 2014 , respectively: Years Ended December 31, 2016 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ 1,890,480 $ 2,717,913 $ 2,153,448 Capitalized Interest Costs 356,196 1,506,172 4,409,544 Total $ 2,246,676 $ 4,224,085 $ 6,562,992 The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below. Years Ended December 31, 2016 2015 2014 Costs Incurred for the Year: Proved Property Acquisition and Other $ 18,531,518 $ 9,068,139 $ 29,838,482 Unproved Property Acquisition 2,301,285 3,346,214 27,561,901 Development 63,621,429 116,255,535 479,472,251 Total $ 84,454,232 $ 128,669,888 $ 536,872,634 |
Summary of capitalized costs excluded from depletion | The following is a summary of capitalized costs excluded from depletion at December 31, 2016 by year incurred. Years Ended December 31, 2016 2015 2014 Prior Years Property Acquisition $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 Development — — — — Total $ 1,110,907 $ 736,514 $ 579,536 $ 196,845 |
Schedule of estimates of its proved crude oil and natural gas reserves | The following tables present the Company’s independent petroleum consultants’ estimates of its proved crude oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Natural Gas Oil BOE Proved Developed and Undeveloped Reserves at December 31, 2013 50,168,133 75,799,125 84,160,481 Revisions of Previous Estimates 2,465,251 (11,397,088 ) (10,986,213 ) Extensions, Discoveries and Other Additions 21,984,514 29,662,181 33,326,267 Production (3,682,781 ) (5,150,913 ) (5,764,710 ) Proved Developed and Undeveloped Reserves at December 31, 2014 70,935,117 88,913,305 100,735,825 Revisions of Previous Estimates (23,552,809 ) (36,277,018 ) (40,202,486 ) Extensions, Discoveries and Other Additions 8,170,259 9,346,864 10,708,574 Production (4,651,583 ) (5,168,687 ) (5,943,951 ) Proved Developed and Undeveloped Reserves at December 31, 2015 50,900,984 56,814,464 65,297,962 Revisions of Previous Estimates (8,697,825 ) (13,995,801 ) (15,445,439 ) Extensions, Discoveries and Other Additions 7,695,309 7,142,439 8,424,991 Purchases of Minerals in Place 960,758 640,108 800,234 Production (4,026,899 ) (4,325,919 ) (4,997,069 ) Proved Developed and Undeveloped Reserves at December 31, 2016 46,832,327 46,275,291 54,080,679 Proved Developed Reserves: December 31, 2013 20,642,967 32,043,405 35,483,900 December 31, 2014 38,277,770 44,666,408 51,046,037 December 31, 2015 33,619,954 36,573,821 42,177,147 December 31, 2016 32,808,111 32,245,139 37,713,158 Proved Undeveloped Reserves: December 31, 2013 29,525,166 43,755,720 48,676,581 December 31, 2014 32,657,347 44,246,897 49,689,788 December 31, 2015 17,281,030 20,240,643 23,120,815 December 31, 2016 14,024,216 14,030,152 16,367,521 |
Summary of standardized measure of discounted future net cash flows | The following table presents a standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating proved crude oil and natural gas were prepared in accordance with the provisions of ASC 932 Extractive Activities - Oil and Gas . Future cash inflows were computed by applying average prices of crude oil and natural gas for the last 12 months to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year end tax rates to future pretax cash flows relating to proved crude oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carry forwards relating to crude oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s crude oil and natural gas reserves. Years Ended December 31, 2016 2015 2014 Future Cash Inflows $ 1,708,870,912 $ 2,470,707,712 $ 7,912,622,500 Future Production Costs (775,534,832 ) (981,256,096 ) (2,281,320,000 ) Future Development Costs (220,869,664 ) (356,401,888 ) (1,453,562,125 ) Future Income Tax Expense (2,477,353 ) (5,740,623 ) (1,058,511,086 ) Future Net Cash Inflows $ 709,989,063 $ 1,127,309,105 $ 3,119,229,289 10% Annual Discount for Estimated Timing of Cash Flows (330,963,050 ) (552,510,342 ) (1,713,849,746 ) Standardized Measure of Discounted Future Net Cash Flows $ 379,026,013 $ 574,798,763 $ 1,405,379,543 |
Schedule of average sales prices | SEC defined prices for each quarter-end in 2016 were as follows: SEC Defined Prices for 12-Months Ended NYMEX Oil Price (per Bbl) Henry Hub Gas Price (per MMBtu) December 31, 2016 $ 42.75 $ 2.49 September 30, 2016 41.68 2.28 June 30, 2016 43.12 2.24 March 31, 2016 46.26 2.39 The twelve month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The price of other liquids is included in natural gas. The prices for the Company’s reserve estimates were as follows: Natural Gas MCF Oil Bbl December 31, 2016 $ 1.67 $ 35.24 December 31, 2015 $ 1.63 $ 42.03 December 31, 2014 $ 7.37 $ 83.11 |
Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% | Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow: Years Ended December 31, 2016 2015 2014 Beginning of Period $ 574,798,763 $ 1,405,379,543 $ 1,224,366,826 Sales of Oil and Natural Gas Produced, Net of Production Costs (98,497,165 ) (128,964,023 ) (330,395,323 ) Extensions and Discoveries 59,542,911 96,770,078 567,026,734 Previously Estimated Development Cost Incurred During the Period 23,271,960 114,208,095 205,125,299 Net Change of Prices and Production Costs (174,656,448 ) (1,384,474,928 ) (52,577,882 ) Change in Future Development Costs 57,481,060 235,578,690 (64,185,447 ) Revisions of Quantity and Timing Estimates (130,664,183 ) (363,975,445 ) (326,674,460 ) Accretion of Discount 57,569,313 170,222,344 152,128,992 Change in Income Taxes 497,950 295,949,531 (79,196 ) Purchases of Minerals in Place 9,576,760 — — Other 105,092 134,104,878 30,644,000 End of Period $ 379,026,013 $ 574,798,763 $ 1,405,379,543 |
QUARTERLY RESULTS OF OPERATIO40
QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of quarterly financial information | Quarterly data for the years end December 31, 2016 and 2015 is as follows: Quarter Ended March 31, June 30, September 30, December 31, 2016 Total Revenues $ 31,836,236 $ 32,014,226 $ 45,109,408 $ 35,943,626 Gains (Losses) on Derivative Instruments, Net 3,463,883 (10,522,948 ) 3,381,564 (11,141,233 ) Total Operating Expenses 141,220,772 124,946,744 74,583,046 33,457,789 Impairment 104,311,122 88,880,921 43,820,791 — Income (Loss) from Operations (109,384,536 ) (92,932,518 ) (29,473,638 ) 2,485,837 Other Income (Expense) (17,181,218 ) (16,046,144 ) (16,145,257 ) (16,218,413 ) Income Tax Benefit — — — (1,402,179 ) Net Loss (126,565,754 ) (108,978,662 ) (45,618,895 ) (12,330,397 ) Net Loss Per Common Share – Basic (2.08 ) (1.78 ) (0.74 ) (0.20 ) Net Loss Per Common Share – Diluted (2.08 ) (1.78 ) (0.74 ) (0.20 ) Quarter Ended March 31, June 30, September 30, December 31, 2015 Total Revenues $ 76,124,638 $ 40,863,194 $ 101,156,552 $ 56,913,029 Gains (Losses) on Derivative Instruments, Net 25,663,283 (22,211,048 ) 51,366,762 17,563,910 Total Operating Expenses 429,607,005 343,402,927 408,323,554 213,112,194 Impairment 360,428,962 281,964,097 354,422,654 167,143,533 Loss from Operations (353,482,367 ) (302,539,733 ) (307,167,002 ) (156,199,165 ) Other Income (Expense) (11,736,205 ) (14,387,494 ) (16,152,574 ) (16,114,205 ) Income Tax Benefit (135,480,000 ) (66,866,610 ) (77,544 ) (50 ) Net Loss (229,738,572 ) (250,060,617 ) (323,242,032 ) (172,313,320 ) Net Loss Per Common Share – Basic (3.79 ) (4.12 ) (5.33 ) (2.84 ) Net Loss Per Common Share – Diluted (3.79 ) (4.12 ) (5.33 ) (2.84 ) |
ORGANIZATION AND NATURE OF BU41
ORGANIZATION AND NATURE OF BUSINESS (Details) | 12 Months Ended |
Dec. 31, 2016a | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Percentage of mineral rights developed | 79.00% |
Gas and oil acreage net mineral rights (in acres) | 155,016 |
SIGNIFICANT ACCOUNTING POLICI42
SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property, Plant and Equipment [Line Items] | ||||
Allowance for doubtful accounts | $ 4.9 | $ 4.5 | ||
Provision for doubtful accounts | 0.8 | 6.2 | $ 1.4 | |
Charged against the allowance for doubtful accounts | $ 0.4 | 3.5 | ||
Period for advance payments to be applied against joint interest billings | 90 days | |||
Depreciation expense | $ 0.2 | $ 0.3 | $ 0.3 | |
Potentially dilutive stock options (in shares) | 391,872 | 141,872 | 141,872 | 241,872 |
Minimum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property and equipment, estimated useful lives | 3 years | |||
Maximum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property and equipment, estimated useful lives | 7 years | |||
Quiet title action in North Dakota [Member] | Other Noncurrent Assets, Net [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Accounts receivable | $ 6.8 | $ 6.8 | ||
Restricted Common Stock [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Potentially dilutive shares (in shares) | 1,905,104 | 2,365,396 | 538,499 | 592,565 |
SIGNIFICANT ACCOUNTING POLICI43
SIGNIFICANT ACCOUNTING POLICIES - Oil and Gas Properties (Details) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016USD ($)$ / bbl$ / MMBTU | Sep. 30, 2016USD ($)$ / bbl$ / MMBTU | Jun. 30, 2016USD ($)$ / bbl$ / MMBTU | Mar. 31, 2016USD ($)$ / bbl$ / MMBTU | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Accounting Policies [Abstract] | |||||||||||
Capitalized Certain Payroll and Other Internal Costs | $ 1,890,480 | $ 2,717,913 | $ 2,153,448 | ||||||||
Capitalized Interest Costs | 356,196 | 1,506,172 | 4,409,544 | ||||||||
Total | $ 2,246,676 | 4,224,085 | 6,562,992 | ||||||||
Minimum percentage of proved reserves sold to be considered a significant alteration | 25.00% | ||||||||||
Proceeds from sale of oil and gas properties | $ 0 | 0 | 0 | ||||||||
Discount rate | 10.00% | ||||||||||
Impairment of Oil and Natural Gas Properties | $ 0 | $ 43,820,791 | $ 88,880,921 | $ 104,311,122 | $ 167,143,533 | $ 354,422,654 | $ 281,964,097 | $ 360,428,962 | $ 237,012,834 | 1,163,959,246 | 0 |
Capitalized costs related to expired leases subject to depletion | $ 13,400,000 | $ 19,000,000 | $ 26,300,000 | ||||||||
NYMEX [Member] | |||||||||||
Defined Price Per Unit [Line Items] | |||||||||||
Defined price for each quarter | $ / bbl | 42.75 | 41.68 | 43.12 | 46.26 | |||||||
Henry Hub [Member] | |||||||||||
Defined Price Per Unit [Line Items] | |||||||||||
Defined price for each quarter | $ / MMBTU | 2.49 | 2.28 | 2.24 | 2.39 |
SIGNIFICANT ACCOUNTING POLICI44
SIGNIFICANT ACCOUNTING POLICIES - Debt Issuance Costs/Restructuring (Details) - USD ($) | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | May 18, 2015 | May 13, 2013 | |
Debt Instrument [Line Items] | |||||
Amortization of debt issuance costs | $ 3,822,967 | $ 3,696,532 | $ 2,776,024 | ||
Write-off of Debt Issuance Costs | 1,089,507 | 0 | 0 | ||
Valuation Allowance | 341,265,900 | 232,260,000 | 0 | ||
Asset impairment charges | 0 | 0 | |||
Debt Issuance Costs, Net [Member] | |||||
Debt Instrument [Line Items] | |||||
Unamortized debt issuance costs | 12,500,000 | ||||
Revolving Credit Facility [Member] | Other Noncurrent Assets, Net [Member] | |||||
Debt Instrument [Line Items] | |||||
Unamortized debt issuance costs | 1,600,000 | 3,300,000 | |||
Severance and Benefit Costs [Member] | |||||
Debt Instrument [Line Items] | |||||
Restructuring costs | 0 | 500,000 | 0 | ||
2013 Equity Incentive Plan [Member] | |||||
Debt Instrument [Line Items] | |||||
Non-cash expense related to acceleration of certain equity awards previously granted | 100,000 | ||||
Senior Notes Due 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Amortization of bond premium | 1,500,000 | 1,500,000 | 1,500,000 | ||
Amortization of bond discount | $ 2,000,000 | $ 1,200,000 | $ 0 | ||
Senior Notes Due 2020 [Member] | 8% Senior Notes Due 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Unamortized debt issuance costs | $ 10,000,000 | $ 10,500,000 | |||
Interest rate percentage | 8.00% | 8.00% |
SIGNIFICANT ACCOUNTING POLICI45
SIGNIFICANT ACCOUNTING POLICIES - Earnings Per Share (Details) - shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accounting Policies [Abstract] | |||
Weighted Average Shares Outstanding - Basic (in shares) | 61,173,547 | 60,652,447 | 60,691,701 |
Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock (in shares) | 0 | 0 | 169,068 |
Weighted Average Common Shares Outstanding - Diluted (in shares) | 61,173,547 | 60,652,447 | 60,860,769 |
Restricted Stock Excluded From EPS Due To The Anti-Dilutive Effect (in shares) | 829,313 | 322,393 | 15,590 |
CRUDE OIL AND NATURAL GAS PRO46
CRUDE OIL AND NATURAL GAS PROPERTIES (Details) | Oct. 06, 2016USD ($)awell | Dec. 31, 2016USD ($)a$ / a | Dec. 31, 2016USD ($)a$ / a | Dec. 31, 2015USD ($)a$ / a | Dec. 31, 2014USD ($)a$ / a |
Business Acquisition [Line Items] | |||||
Capital expenditures incurred but not yet paid | $ 50,700,000 | $ 59,500,000 | |||
Mineral acres acquired, net (in acres) | a | 3,399 | 4,355 | 22,668 | ||
Average acquisition cost per net acre (in dollars per acre) | $ / a | 1,515 | 1,515 | 1,314 | 1,534 | |
Unproven leasehold interests | a | 26,432 | 26,432 | 38,003 | ||
Anticipated future period over which excluded costs will become subject to depletion | 5 years | ||||
Impairment costs related to expired leases subject to depletion | $ 7,000,000 | $ 37,600,000 | $ 21,400,000 | ||
Definitive Purchase and Sale Agreement with Third Party [Member] | |||||
Business Acquisition [Line Items] | |||||
Mineral acres acquired, net (in acres) | a | 3.8 | ||||
Producing oil and gas wells, gross (in wells) | well | 144 | ||||
Cash consideration | $ 9,400,000 | ||||
Payments to acquire producing properties | 8,900,000 | ||||
Reimbursement of drilling costs in process wells | $ 500,000 | ||||
Revenue since acquisition | $ 1,200,000 | ||||
Operating expenses since acquisition | 500,000 | ||||
Transaction costs | 0 | ||||
Goodwill | $ 0 | $ 0 |
CRUDE OIL AND NATURAL GAS PRO47
CRUDE OIL AND NATURAL GAS PROPERTIES - Capitalized Costs (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||
Property Acquisition | $ 1,110,907 | $ 736,514 | $ 579,536 | $ 196,845 |
Development | 0 | 0 | 0 | 0 |
Total | $ 1,110,907 | $ 736,514 | $ 579,536 | $ 196,845 |
LONG TERM DEBT - Schedule of Lo
LONG TERM DEBT - Schedule of Long Term Debt (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Line of Credit Facility [Line Items] | ||
Long-term Debt | $ 842,306,153 | $ 847,804,829 |
Debt Issuance Costs, Net | (9,681,028) | (12,514,500) |
Long-term Debt, Net | 832,625,125 | 835,290,329 |
Line of Credit [Member] | Revolving Credit Facility [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | 144,000,000 | 150,000,000 |
Debt Issuance Costs, Net | 0 | 0 |
Long-term Debt, Net | 144,000,000 | 150,000,000 |
8% Senior Notes [Member] | Senior Notes [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | 698,306,153 | 697,804,829 |
Debt Issuance Costs, Net | (9,681,028) | (12,514,500) |
Long-term Debt, Net | $ 688,625,125 | $ 685,290,329 |
Interest rate percentage | 8.00% |
LONG TERM DEBT (Details)
LONG TERM DEBT (Details) | 12 Months Ended | |||
Dec. 31, 2016USD ($) | May 18, 2015USD ($) | May 13, 2013USD ($) | May 18, 2012USD ($) | |
8% Senior Notes Due 2020 [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Percentage of notes at redemption prices for the twelve-month period beginning on June 1, 2016 | 104.00% | |||
Percentage of notes at redemption prices for the twelve-month period beginning on June 1, 2017 | 102.00% | |||
Percentage of notes at redemption prices for beginning on June 1, 2018 | 100.00% | |||
Number of days in default payment of interest | 30 days | |||
Payment of certain final judgments | $ 25,000,000 | |||
Number of days related to payment certain final judgments | 60 days | |||
8% Senior Notes Due 2020 [Member] | The "Original Notes" [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Principal amount of senior unsecured notes | $ 300,000,000 | |||
Interest rate percentage | 8.00% | |||
Maturity date | Jun. 1, 2020 | |||
Net proceeds from issuance of senior unsecured notes | $ 291,200,000 | |||
8% Senior Notes Due 2020 [Member] | The "2013 Follow-on Notes" [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Interest rate percentage | 8.00% | |||
Maturity date | Jun. 1, 2020 | |||
Price of senior unsecured notes | 105.25% | |||
Additional amount of senior unsecured notes | $ 200,000,000 | |||
Net proceeds from issuance of senior unsecured notes | $ 200,100,000 | |||
8% Senior Notes Due 2020 [Member] | The "2015 Mirror Notes" [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Interest rate percentage | 8.00% | |||
Maturity date | Jun. 1, 2020 | |||
Price of senior unsecured notes | 95.00% | |||
Additional amount of senior unsecured notes | $ 200,000,000 | |||
Net proceeds from issuance of senior unsecured notes | $ 184,900,000 | |||
Revolving Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Revolving credit facility, maximum borrowing | 750,000,000 | |||
Borrowing base | 350,000,000 | |||
Borrowings under Credit Facility | 144,000,000 | |||
Remaining borrowing capacity of Credit Facility | 206,000,000 | |||
Loans issued under revolving credit facility | $ 144,000,000 | |||
Weighted average interest rate | 3.02% | |||
Line of credit facility covenant terms current ratio | 1 | |||
Line of credit facility ratio of debt to EBITDAX | 2.5 | |||
Line of credit facility ratio of EBITDAX to interest expense | 1.75 | |||
Revolving Credit Facility [Member] | Minimum [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Commitment fee percentage | 0.375% | |||
Revolving Credit Facility [Member] | Maximum [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Commitment fee percentage | 0.50% | |||
Revolving Credit Facility [Member] | LIBOR [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Interest rate margin in effect during period | 2.25% | |||
Commitment fee percentage | 0.375% | |||
Revolving Credit Facility [Member] | LIBOR [Member] | Minimum [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Interest rate margin in effect during period | 2.00% | |||
Revolving Credit Facility [Member] | LIBOR [Member] | Maximum [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Interest rate margin in effect during period | 3.00% | |||
Revolving Credit Facility [Member] | Alternate Base Rate [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Interest rate margin in effect during period | 1.25% | |||
Revolving Credit Facility [Member] | Alternate Base Rate [Member] | Minimum [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Interest rate margin in effect during period | 1.00% | |||
Revolving Credit Facility [Member] | Alternate Base Rate [Member] | Maximum [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Interest rate margin in effect during period | 2.00% |
LONG TERM DEBT - Debt Covenants
LONG TERM DEBT - Debt Covenants (Details) - Revolving Credit Facility [Member] | Dec. 31, 2016 |
Debt Instrument [Line Items] | |
Line of credit facility ratio of EBITDAX to interest expense | 1.75 |
Measurement Period 1 [Member] | |
Debt Instrument [Line Items] | |
Line of credit facility ratio of EBITDAX to interest expense | 1.75 |
Measurement Period 2 [Member] | |
Debt Instrument [Line Items] | |
Line of credit facility ratio of EBITDAX to interest expense | 1.50 |
Measurement Period 3 [Member] | |
Debt Instrument [Line Items] | |
Line of credit facility ratio of EBITDAX to interest expense | 1.25 |
Measurement Period 4 [Member] | |
Debt Instrument [Line Items] | |
Line of credit facility ratio of EBITDAX to interest expense | 1.25 |
Measurement Period 5 [Member] | |
Debt Instrument [Line Items] | |
Line of credit facility ratio of EBITDAX to interest expense | 1 |
Measurement Period 6 [Member] | |
Debt Instrument [Line Items] | |
Line of credit facility ratio of EBITDAX to interest expense | 1 |
Measurement Period 7 [Member] | |
Debt Instrument [Line Items] | |
Line of credit facility ratio of EBITDAX to interest expense | 2.50 |
COMMON AND PREFERRED STOCK (Det
COMMON AND PREFERRED STOCK (Details) | 1 Months Ended | 12 Months Ended | ||||
May 31, 2016shares | Dec. 31, 2016USD ($)Class$ / sharesshares | Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014USD ($)shares | Apr. 30, 2016shares | May 31, 2011USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Percent increase in shares authorized | 50.00% | |||||
Common stock, shares authorized (in shares) | 142,500,000 | 142,500,000 | 142,500,000 | 95,000,000 | ||
Total shares of preferred and common stock authorized for issuance (in shares) | 147,500,000 | |||||
Number of classes of shares | Class | 2 | |||||
Common stock, par value (in dollars per share) | $ / shares | $ 0.001 | $ 0.001 | ||||
Preferred stock, shares authorized (in shares) | 5,000,000 | 5,000,000 | ||||
Preferred stock, par value (in dollars per share) | $ / shares | $ 0.001 | $ 0.001 | ||||
Common stock surrendered by certain employees to cover tax obligations (in shares) | 375,875 | 57,929 | 43,835 | |||
Shares forfeited (in shares) | 375,875 | 57,929 | 79,461 | |||
Fair value of common stock surrendered by certain employees to cover tax obligations | $ | $ 1,400,000 | $ 277,000 | $ 587,000 | |||
Stock options exercised (in shares) | 0 | 0 | 100,000 | |||
Increase in other shares (in shares) | (1,594,542) | (1,397) | 42,443 | |||
Stock repurchase program, amount approved | $ | $ 150,000,000 | |||||
Stock repurchase (in shares) | 0 | 0 | (1,153,885) | |||
Treasury stock, repurchased and retired | $ | $ 15,500,000 | |||||
Chief Executive Officer [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Common stock surrendered by certain employees related to termination of employment (in shares) | 1,400,000 | |||||
Employee [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Restricted stock forfeitures (in shares) | 1,397 | |||||
Director [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Stock options exercised (in shares) | 100,000 | |||||
Aggregate exercise price of stock surrendered | $ | $ 518,000 | |||||
Shares surrendered to cover aggregate exercise price (in shares) | 35,626 | |||||
Restricted Common Stock [Member] | Chief Executive Officer [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares forfeited (in shares) | 1,530,796 | |||||
Reversal of compensation expense | $ | $ 1,800,000 |
COMMON AND PREFERRED STOCK - Co
COMMON AND PREFERRED STOCK - Common Stock Outstanding (Details) - shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Changes in number of common stock shares [Roll forward] | |||
Beginning Balance (in shares) | 63,120,384 | 61,066,712 | 61,858,199 |
Stock Options Exercised (in shares) | 0 | 0 | 100,000 |
Restricted Stock Grants (in shares) | 2,109,814 | 2,112,998 | 299,416 |
Stock repurchase (in shares) | 0 | 0 | (1,153,885) |
Other Surrenders (in shares) | (375,875) | (57,929) | (79,461) |
Other (in shares) | (1,594,542) | (1,397) | 42,443 |
Ending balance (in shares) | 63,259,781 | 63,120,384 | 61,066,712 |
STOCK OPTIONS_STOCK-BASED COM53
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS (Details) - USD ($) $ / shares in Units, $ in Millions | Feb. 12, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | May 31, 2016 |
2013 Equity Incentive Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Additional shares were authorized for grant (in shares) | 1,600,000 | ||||
Shares available for future awards (in shares) | 3,700,000 | ||||
Restricted Stock Awards [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Shares issued (in shares) | 2,109,814 | 2,112,998 | 299,416 | ||
Unrecognized compensation expense | $ 9.2 | ||||
Unrecognized compensation expense, recognized period | 2 years 4 months 24 days | ||||
Percent of forfeiture rate assumed for restricted stock | 0.00% | ||||
Stock Option Awards [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Risk-free interest rate | 1.15% | ||||
Stock Option Awards [Member] | 2006 Incentive Stock Option Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Shares granted (in shares) | 560,000 | ||||
Grant price per share (in dollars per share) | $ 5.18 | ||||
Stock Option Awards [Member] | 2013 Equity Incentive Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Grant price per share (in dollars per share) | $ 2.79 | ||||
Share-based compensation expense | $ 0.4 | ||||
Stock Option Awards [Member] | Directors [Member] | 2006 Incentive Stock Option Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Shares granted (in shares) | 500,000 | ||||
Stock Option Awards [Member] | Directors [Member] | 2013 Equity Incentive Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Shares granted (in shares) | 250,000 | ||||
Stock Option Awards [Member] | Employee [Member] | 2006 Incentive Stock Option Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Shares granted (in shares) | 60,000 | ||||
Performance Shares [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based compensation expense | $ 0.1 | ||||
Vesting period | 3 years | ||||
Risk-free interest rate | 0.49% | ||||
Maximum dollar amount of performance shares issuable | $ 1.7 | ||||
Minimum [Member] | Performance Shares [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Participants earning percentage | 0.00% | ||||
Maximum [Member] | Performance Shares [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Participants earning percentage | 150.00% | ||||
Risk-free interest rate | 83.30% |
STOCK OPTIONS_STOCK-BASED COM54
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS - Restricted Stock Activity (Details) - Restricted Stock Awards [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Number of Shares | |||
Beginning of the Year (in shares) | 2,365,396 | 538,499 | 592,565 |
Shares Granted (in shares) | 2,109,814 | 2,112,998 | 299,416 |
Shares Forfeited (in shares) | (1,594,542) | (1,397) | 0 |
Lapse of Restrictions (in shares) | (975,564) | (284,704) | (353,482) |
End of the Year (in shares) | 1,905,104 | 2,365,396 | 538,499 |
Weighted- Average Price | |||
Beginning of the Year (in dollars per share) | $ 7.15 | $ 13.54 | $ 16.84 |
Shares Granted (in dollars per share) | 3.83 | 6.29 | 12.09 |
Shares Forfeited (in dollars per share) | 4.67 | 15 | 0 |
Lapse of Restrictions (in dollars per share) | 7.34 | 12.24 | 17.84 |
End of the Year (in dollars per share) | $ 4.59 | $ 7.15 | $ 13.54 |
STOCK OPTIONS_STOCK-BASED COM55
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS - Stock Option Activity (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Stock Option Awards | ||||
Beginning Balance (in shares) | 141,872 | 141,872 | 241,872 | |
Granted (in shares) | 250,000 | 0 | 0 | |
Exercised (in shares) | 0 | 0 | (100,000) | |
Expired or canceled (in shares) | 0 | 0 | 0 | |
Forfeited (in shares) | 0 | 0 | 0 | |
Ending Balance (in shares) | 391,872 | 141,872 | 141,872 | 241,872 |
Weighted-Average Price | ||||
Beginning Balance (in dollars per share) | $ 5.18 | $ 5.18 | $ 5.18 | |
Granted (in dollars per share) | 2.79 | 0 | 0 | |
Exercised (in dollars per share) | 0 | 0 | 5.18 | |
Expired or canceled (in dollars per share) | 0 | 0 | 0 | |
Forfeited (in dollars per share) | 0 | 0 | 0 | |
Ending Balance (in dollars per share) | $ 3.66 | $ 5.18 | $ 5.18 | $ 5.18 |
Weighted Average Contractual Term | 2 years 10 months 24 days | 1 year 9 months 18 days | 2 years 9 months 18 days | 3 years 9 months 18 days |
Intrinsic Value | $ 0 | $ 0 | $ 66,680 | $ 2,392,000 |
STOCK OPTIONS_STOCK-BASED COM56
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS - Valuation Assumptions (Details) - Stock Option Awards [Member] | Feb. 12, 2016$ / shares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Risk-free interest rate | 1.15% |
Expected life | 5 years |
Expected volatility | 61.89% |
Fair value per option (in dollars per share) | $ 1.47 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - 8% Senior Unsecured Notes Due 2020 [Member] - USD ($) $ in Millions | Dec. 31, 2016 | Sep. 30, 2016 |
Related Party Transaction [Line Items] | ||
Interest rate percentage | 8.00% | |
Investments of TRT Holdings, Inc. and Affiliates [Member] | ||
Related Party Transaction [Line Items] | ||
Notes payable | $ 200 |
COMMITMENTS & CONTINGENCIES (De
COMMITMENTS & CONTINGENCIES (Details) - USD ($) $ in Millions | Aug. 16, 2016 | Aug. 15, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Loss Contingencies [Line Items] | |||||
Shares forfeited (in shares) | 375,875 | 57,929 | 79,461 | ||
Chief Executive Officer [Member] | Michael Reger [Member] | |||||
Loss Contingencies [Line Items] | |||||
Reduction in revenue | $ 1.6 | ||||
Other Noncurrent Assets, Net [Member] | Quiet title action in North Dakota [Member] | |||||
Loss Contingencies [Line Items] | |||||
Possible revenue to be reversed due to pending litigation | $ 6.8 | $ 6.8 | |||
Common Stock [Member] | Chief Executive Officer [Member] | |||||
Loss Contingencies [Line Items] | |||||
Shares forfeited (in shares) | 1,530,796 |
ASSET RETIREMENT OBLIGATION (De
ASSET RETIREMENT OBLIGATION (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset retirement obligation [Roll Forward] | ||
Beginning Asset Retirement Obligation | $ 5,816,356 | $ 5,105,762 |
Liabilities Acquired or Incurred During the Period | 585,729 | 475,306 |
Liabilities Removed Due to Divestitures | (21,426) | 0 |
Revision of Estimates | 789,003 | (53,912) |
Accretion of Discount on Asset Retirement Obligations | 405,991 | 372,461 |
Liabilities Settled During the Period | (67,353) | (83,261) |
Ending Asset Retirement Obligation | $ 7,508,300 | $ 5,816,356 |
INCOME TAXES - Income Tax Expen
INCOME TAXES - Income Tax Expense (Benefit) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income tax provision (benefit) [Abstract] | |||||||||||
Current | $ (1,402,179) | $ (73,649) | $ 3,259,445 | ||||||||
Deferred | |||||||||||
Federal | (99,298,900) | (398,002,555) | 87,625,430 | ||||||||
State | (9,707,000) | (36,608,000) | 8,482,125 | ||||||||
Valuation Allowance | 109,005,900 | 232,260,000 | 0 | ||||||||
Total Expense (Benefit) | $ (1,402,179) | $ 0 | $ 0 | $ 0 | $ (50) | $ (77,544) | $ (66,866,610) | $ (135,480,000) | $ (1,402,179) | $ (202,424,204) | $ 99,367,000 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reconciliation of reported amount of income tax expense (benefit) [Abstract] | |||||||||||
Income (Loss) Before Taxes and NOL | $ (294,895,887) | $ (1,177,778,745) | $ 263,112,945 | ||||||||
Federal Statutory Rate | 35.00% | 35.00% | 35.00% | ||||||||
Taxes Computed at Federal Statutory Rates | $ (103,214,000) | $ (412,223,000) | $ 92,090,000 | ||||||||
State Taxes, Net of Federal Taxes | (6,306,000) | (23,825,000) | 5,404,300 | ||||||||
Non-Deductible Compensation | 82,000 | 470,000 | 456,000 | ||||||||
Share Based Compensation Tax Deficiency | (834,900) | 307,000 | 1,472,000 | ||||||||
Other | (135,179) | 586,796 | (55,300) | ||||||||
Valuation Allowance | 109,005,900 | 232,260,000 | 0 | ||||||||
Total Expense (Benefit) | $ (1,402,179) | $ 0 | $ 0 | $ 0 | $ (50) | $ (77,544) | $ (66,866,610) | $ (135,480,000) | (1,402,179) | (202,424,204) | 99,367,000 |
Alternative minimum tax credit | 1,400,000 | 1,400,000 | |||||||||
Interest or penalties expense | 0 | 0 | $ 0 | ||||||||
Interest or penalties accrued | 0 | $ 0 | 0 | $ 0 | |||||||
Federal [Member] | |||||||||||
Reconciliation of reported amount of income tax expense (benefit) [Abstract] | |||||||||||
Net operating loss carryforward | 605,400,000 | 605,400,000 | |||||||||
Alternative minimum tax credit | $ 1,700,000 | $ 1,700,000 |
INCOME TAXES - Deferred Tax Ass
INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Income Tax Disclosure [Abstract] | |||
Net Operating Loss (NOLs) and Tax Credit Carryforwards | $ 224,679,900 | $ 195,207,000 | |
Share Based Compensation | 1,032,000 | 1,762,000 | |
Accrued Interest | 1,727,000 | 1,723,000 | |
Allowance for Doubtful Accounts | 1,795,000 | 1,662,000 | |
Crude Oil and Natural Gas Properties and Other Properties | 107,642,000 | 55,939,000 | |
Derivative Instruments | 4,341,000 | (23,855,000) | |
Other | 49,000 | (178,000) | |
Total Net Deferred Tax Assets (Liabilities) Before Valuation Allowance | 341,265,900 | 232,260,000 | |
Valuation Allowance | (341,265,900) | (232,260,000) | $ 0 |
Total Net Deferred Tax Assets (Liabilities) | $ 0 | $ 0 |
OPERATING LEASES (Details)
OPERATING LEASES (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating Leased Assets [Line Items] | |||
Rent expense | $ 320 | $ 287 | $ 267 |
Future minimum lease payments [Abstract] | |||
2,017 | 382 | ||
2,018 | 342 | ||
2,019 | 352 | ||
2,020 | 361 | ||
2,021 | 340 | ||
Total | 1,777 | ||
Vehicles [Member] | |||
Operating Leased Assets [Line Items] | |||
Rent expense | $ 26 | $ 45 | $ 30 |
FAIR VALUE (Details)
FAIR VALUE (Details) - Fair Value, Measurements, Recurring [Member] - Significant Other Observable Inputs (Level 2) [Member] - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity Derivatives – Current Assets (crude oil swaps) | $ 4,517 | $ 64,611,558 |
Commodity Derivatives – Current Liabilities (crude oil swaps and collars) | (10,001,564) | |
Commodity Derivatives – Non-Current Liabilities (crude oil swaps) | (1,738,329) | |
Total | $ (11,735,376) | $ 64,611,558 |
FAIR VALUE - Additional Informa
FAIR VALUE - Additional Information (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt | $ 832,625,125 | $ 835,290,329 |
Debt instrument, unamortized discount | 1,700,000 | |
Asset retirement obligations | 585,729 | $ 475,306 |
Carrying Amount [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Senior unsecured notes | 688,600,000 | |
Revolving credit facility | 144,000,000 | |
Estimated Fair Value [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Senior unsecured notes | $ 589,000,000 |
DERIVATIVE INSTRUMENTS AND PR66
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT - Gains/Losses on Derivatives (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||||||||||
Cash Received (Paid) on Derivatives | $ 61,528,201 | $ 161,098,510 | $ (7,863,104) | ||||||||
Non-Cash Gain (Loss) on Derivatives | (76,346,935) | (88,715,603) | 171,275,719 | ||||||||
Gain (Loss) on Derivative Instruments, Net | $ (11,141,233) | $ 3,381,564 | $ (10,522,948) | $ 3,463,883 | $ 17,563,910 | $ 51,366,762 | $ (22,211,048) | $ 25,663,283 | $ (14,818,734) | 72,382,907 | $ 163,412,615 |
Crude Oil Collars [Member] | |||||||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||||||
Net cash receipts for crude oil collars | $ 202,000 |
DERIVATIVE INSTRUMENTS AND PR67
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Details) | Jun. 30, 2017bbl | Dec. 31, 2017$ / bblbbl | Dec. 31, 2016bbl$ / bbl |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Volumes (in bbl) | bbl | 3,300,000 | ||
Weighted Average Price (in dollar per bbl) | 53 | ||
Oil Swap 1 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 360,000 | ||
Fixed Price (in dollars per bbl) | 50 | ||
Oil Swap 2 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 180,000 | ||
Fixed Price (in dollars per bbl) | 50.01 | ||
Oil Swap 3 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 180,000 | ||
Fixed Price (in dollars per bbl) | 49.99 | ||
Oil Swap 4 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 60,000 | ||
Fixed Price (in dollars per bbl) | 55.20 | ||
Oil Swap 5 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 360,000 | ||
Fixed Price (in dollars per bbl) | 54.20 | ||
Oil Swap 6 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 240,000 | ||
Fixed Price (in dollars per bbl) | 53.25 | ||
Oil Swap 7 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 365,000 | ||
Fixed Price (in dollars per bbl) | 54.10 | ||
Oil Swap 8 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 240,000 | ||
Fixed Price (in dollars per bbl) | 52.75 | ||
Oil Swap 9 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 120,000 | ||
Fixed Price (in dollars per bbl) | 52.75 | ||
Oil Swap 10 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 120,000 | ||
Fixed Price (in dollars per bbl) | 53.50 | ||
Oil Swap 11 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 60,000 | ||
Fixed Price (in dollars per bbl) | 54.60 | ||
Oil Swap 12 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 120,000 | ||
Fixed Price (in dollars per bbl) | 51.75 | ||
Oil Swap 13 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 120,000 | ||
Fixed Price (in dollars per bbl) | 53.75 | ||
Oil Swap 14 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 270,000 | ||
Fixed Price (in dollars per bbl) | 54 | ||
Oil Swap 16 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 270,000 | ||
Fixed Price (in dollars per bbl) | 54 | ||
Oil Swap 17 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 273,000 | ||
Fixed Price (in dollars per bbl) | 55.20 | ||
Open Commodity Swap 1 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Volumes (in bbl) | bbl | 2,525,000 | ||
Weighted Average Price (in dollar per bbl) | 52.55 | ||
Open Commodity Swap 2 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Volumes (in bbl) | bbl | 813,000 | ||
Weighted Average Price (in dollar per bbl) | 54.40 | ||
Costless Collar Agreement 1 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 180,000 | ||
Costless Collar Agreement 1 [Member] | Minimum [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Fixed Price (in dollars per bbl) | 50 | ||
Costless Collar Agreement 1 [Member] | Maximum [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Fixed Price (in dollars per bbl) | 60 | ||
Costless Collar Agreement 2 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Oil (in bbl) | bbl | 120,000 | ||
Costless Collar Agreement 2 [Member] | Minimum [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Fixed Price (in dollars per bbl) | 50 | ||
Costless Collar Agreement 2 [Member] | Maximum [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Fixed Price (in dollars per bbl) | 60.15 | ||
Forecast [Member] | Oil Swap 10 [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Notional amount exercisable upon extension of contract (in bbl) | bbl | 10,000 | ||
Additional volume if all options exercised (in bbl) | bbl | 10,000 | ||
Average fixed price of additional volume (in dollars per bbl) | 55.20 |
DERIVATIVE INSTRUMENTS AND PR68
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT - Classification of outstanding financial instruments (Details) - Not Designated as Hedging Instrument [Member] - Cash Flow Hedging [Member] - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Derivatives, Fair Value [Line Items] | ||
Total Derivatives Assets | $ 4,517 | $ 64,611,558 |
Total Derivatives Liabilities | (11,739,893) | 0 |
Swap Contracts [Member] | Current Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total Derivatives Assets | 4,517 | 64,611,558 |
Swap Contracts [Member] | Current Assets/Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total Derivatives Liabilities | (9,512,724) | 0 |
Swap Contracts [Member] | Non Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total Derivatives Liabilities | (1,738,329) | 0 |
Swaption Contracts [Member] | Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total Derivatives Liabilities | (333,046) | 0 |
Costless Collars [Member] | Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total Derivatives Liabilities | $ (155,794) | $ 0 |
DERIVATIVE INSTRUMENTS AND PR69
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT - Reconciliation between the gross assets and liabilities and the amounts reflected on the balance sheet (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Offsetting Assets [Line Items] | ||
Gross Amounts of Recognized Assets, Offsetting of Derivative Assets | $ 20,962 | $ 64,611,558 |
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets | (16,445) | 0 |
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets | 4,517 | 64,611,558 |
Gross Amounts of Recognized Assets, Offsetting of Derivative Liabilities | (11,756,338) | 0 |
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities | 16,445 | 0 |
Net Amount of Assets Presented in Balance Sheet, Offsetting of Derivative Liabilities | (11,739,893) | 0 |
Current Assets [Member] | ||
Offsetting Assets [Line Items] | ||
Gross Amounts of Recognized Assets, Offsetting of Derivative Assets | 20,962 | 64,611,558 |
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets | (16,445) | 0 |
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets | 4,517 | 64,611,558 |
Non Current Assets [Member] | ||
Offsetting Assets [Line Items] | ||
Gross Amounts of Recognized Assets, Offsetting of Derivative Assets | 0 | 0 |
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets | 0 | 0 |
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets | 0 | 0 |
Current Liabilities [Member] | ||
Offsetting Assets [Line Items] | ||
Gross Amounts of Recognized Assets, Offsetting of Derivative Liabilities | (10,018,009) | 0 |
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities | 16,445 | 0 |
Net Amount of Assets Presented in Balance Sheet, Offsetting of Derivative Liabilities | (10,001,564) | 0 |
Non Current Liabilities [Member] | ||
Offsetting Assets [Line Items] | ||
Gross Amounts of Recognized Assets, Offsetting of Derivative Liabilities | (1,738,329) | 0 |
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities | 0 | 0 |
Net Amount of Assets Presented in Balance Sheet, Offsetting of Derivative Liabilities | $ (1,738,329) | $ 0 |
EARNINGS PER SHARE (Details)
EARNINGS PER SHARE (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Basic EPS [Abstract] | |||||||||||
Net Income (Loss) | $ (12,330,397) | $ (45,618,895) | $ (108,978,662) | $ (126,565,754) | $ (172,313,320) | $ (323,242,032) | $ (250,060,617) | $ (229,738,572) | $ (293,493,708) | $ (975,354,541) | $ 163,745,945 |
Shares-Basic (in shares) | 61,173,547 | 60,652,447 | 60,691,701 | ||||||||
Net Income (Loss) Per Common Share - Common (in dollars per share) | $ (0.20) | $ (0.74) | $ (1.78) | $ (2.08) | $ (2.84) | $ (5.33) | $ (4.12) | $ (3.79) | $ (4.80) | $ (16.08) | $ 2.70 |
Diluted EPS [Abstract] | |||||||||||
Dilutive Effect of Options (in shares) | 0 | 0 | 169,068 | ||||||||
Dilutive Effect of Options (in dollars per share) | $ 0 | $ 0 | $ (0.01) | ||||||||
Net Income (Loss) available to common shareholders, diluted | $ (293,493,708) | $ (975,354,541) | $ 163,745,945 | ||||||||
Weighted Average Common Shares Outstanding - Diluted (in shares) | 61,173,547 | 60,652,447 | 60,860,769 | ||||||||
Net Income (Loss) Per Common Share - Diluted (in dollars per share) | $ (0.20) | $ (0.74) | $ (1.78) | $ (2.08) | $ (2.84) | $ (5.33) | $ (4.12) | $ (3.79) | $ (4.80) | $ (16.08) | $ 2.69 |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||||||||||
Shares excluded from EPS due to the anti-dilutive effect (in shares) | 829,313 | 322,393 | 15,590 | ||||||||
Restricted Stock [Member] | |||||||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||||||||||
Shares excluded from EPS due to the anti-dilutive effect (in shares) | 829,313 | 322,393 | 15,590 |
RESTRUCTURING COSTS (Details)
RESTRUCTURING COSTS (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Restructuring and Related Cost [Abstract] | ||
Restructuring costs | $ 0 | |
Restructuring Reserve [Roll Forward] | ||
Restructuring Liability | 32,493 | |
Additions | 0 | |
Settlements | (32,493) | |
Revisions | 0 | |
Restructuring Liability | $ 0 | $ 32,493 |
Severance and Benefit Costs [Member] | General and Administrative Expense [Member] | ||
Restructuring and Related Cost [Abstract] | ||
Restructuring costs | 523,487 | |
Restructuring Reserve [Roll Forward] | ||
Additions | $ 523,487 |
EMPLOYEE BENEFIT PLANS (Details
EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Compensation Related Costs [Abstract] | |||
Percentage match of eligible employee's deferral contribution | 100.00% | 100.00% | 100.00% |
Maximum percentage of eligible employee's deferral contribution matched | 8.00% | 8.00% | 8.00% |
Matching contributions to the Plans | $ 238 | $ 279 | $ 269 |
SUPPLEMENTAL OIL AND GAS INFO73
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Costs Incurred (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Extractive Industries [Abstract] | |||
Proved Property Acquisition and Other | $ 18,531,518 | $ 9,068,139 | $ 29,838,482 |
Unproved Property Acquisition | 2,301,285 | 3,346,214 | 27,561,901 |
Development | 63,621,429 | 116,255,535 | 479,472,251 |
Total | $ 84,454,232 | $ 128,669,888 | $ 536,872,634 |
SUPPLEMENTAL OIL AND GAS INFO74
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Capitalized Costs (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Extractive Industries [Abstract] | ||||
Property Acquisition | $ 1,110,907 | $ 736,514 | $ 579,536 | $ 196,845 |
Development | 0 | 0 | 0 | 0 |
Total | $ 1,110,907 | $ 736,514 | $ 579,536 | $ 196,845 |
SUPPLEMENTAL OIL AND GAS INFO75
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Proved Reserve Data (Details) | 12 Months Ended | ||||||||||||
Dec. 31, 2016BoeMcfbbl | Dec. 31, 2016BoeMcfbbl | Dec. 31, 2016BoeMcfbbl | Dec. 31, 2016BoeMMBoeMcfbbl | Dec. 31, 2015BoeMcfbbl | Dec. 31, 2015BoeMcfbbl | Dec. 31, 2015BoeMcfbbl | Dec. 31, 2015BoeMMBoeMcfbbl | Dec. 31, 2014BoeMcfbbl | Dec. 31, 2014BoeMcfbbl | Dec. 31, 2014BoeMcfbbl | Dec. 31, 2014BoeMMBoeMcfbbl | Dec. 31, 2013BoeMcfbbl | |
Natural Gas | |||||||||||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||||||||||
Proved Developed and Undeveloped Reserves, Beginning Balance | Mcf | 50,900,984 | 70,935,117 | 50,168,133 | ||||||||||
Revisions of Previous Estimates | Mcf | (8,697,825) | (23,552,809) | 2,465,251 | ||||||||||
Extensions, Discoveries and Other Additions | Mcf | 7,695,309 | 8,170,259 | 21,984,514 | ||||||||||
Purchases of Minerals in Place | Mcf | 960,758 | ||||||||||||
Production | Mcf | (4,026,899) | (4,651,583) | (3,682,781) | ||||||||||
Proved Developed and Undeveloped Reserves, Ending Balance | Mcf | 46,832,327 | 50,900,984 | 70,935,117 | ||||||||||
Proved Developed Reserves | Mcf | 32,808,111 | 32,808,111 | 32,808,111 | 32,808,111 | 33,619,954 | 33,619,954 | 33,619,954 | 33,619,954 | 38,277,770 | 38,277,770 | 38,277,770 | 38,277,770 | 20,642,967 |
Proved Undeveloped Reserve | Mcf | 14,024,216 | 14,024,216 | 14,024,216 | 14,024,216 | 17,281,030 | 17,281,030 | 17,281,030 | 17,281,030 | 32,657,347 | 32,657,347 | 32,657,347 | 32,657,347 | 29,525,166 |
Oil | |||||||||||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||||||||||
Proved Developed and Undeveloped Reserves, Beginning Balance | bbl | 56,814,464 | 88,913,305 | 75,799,125 | ||||||||||
Revisions of Previous Estimates | bbl | (13,995,801) | (36,277,018) | (11,397,088) | ||||||||||
Extensions, Discoveries and Other Additions | bbl | 7,142,439 | 9,346,864 | 29,662,181 | ||||||||||
Purchases of Minerals in Place | bbl | 640,108 | ||||||||||||
Production | bbl | (4,325,919) | (5,168,687) | (5,150,913) | ||||||||||
Proved Developed and Undeveloped Reserves, Ending Balance | bbl | 46,275,291 | 56,814,464 | 88,913,305 | ||||||||||
Proved Developed Reserves | bbl | 32,245,139 | 32,245,139 | 32,245,139 | 32,245,139 | 36,573,821 | 36,573,821 | 36,573,821 | 36,573,821 | 44,666,408 | 44,666,408 | 44,666,408 | 44,666,408 | 32,043,405 |
Proved Undeveloped Reserve | bbl | 14,030,152 | 14,030,152 | 14,030,152 | 14,030,152 | 20,240,643 | 20,240,643 | 20,240,643 | 20,240,643 | 44,246,897 | 44,246,897 | 44,246,897 | 44,246,897 | 43,755,720 |
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward] | |||||||||||||
Proved Developed and Undeveloped Reserves, Beginning Balance | Boe | 65,297,962 | 100,735,825 | 84,160,481 | ||||||||||
Revisions of Previous Estimates | (15,445,439) | (15.4) | (40,202,486) | (40.2) | (10,986,213) | (11) | |||||||
Extensions, Discoveries and Other Additions | Boe | 8,424,991 | 10,708,574 | 33,326,267 | ||||||||||
Purchases of Minerals in Place | Boe | 800,234 | ||||||||||||
Production | Boe | (4,997,069) | (5,943,951) | (5,764,710) | ||||||||||
Proved Developed and Undeveloped Reserves, Ending Balance | Boe | 54,080,679 | 65,297,962 | 100,735,825 | ||||||||||
Proved Developed Reserves | Boe | 37,713,158 | 37,713,158 | 37,713,158 | 37,713,158 | 42,177,147 | 42,177,147 | 42,177,147 | 42,177,147 | 51,046,037 | 51,046,037 | 51,046,037 | 51,046,037 | 35,483,900 |
Proved Undeveloped Reserves | Boe | 16,367,521 | 16,367,521 | 16,367,521 | 16,367,521 | 23,120,815 | 23,120,815 | 23,120,815 | 23,120,815 | 49,689,788 | 49,689,788 | 49,689,788 | 49,689,788 | 48,676,581 |
SUPPLEMENTAL OIL AND GAS INFO76
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Additional Information (Details) | 12 Months Ended | |||||
Dec. 31, 2016Boe | Dec. 31, 2016MMBoe | Dec. 31, 2015Boe | Dec. 31, 2015MMBoe | Dec. 31, 2014Boe | Dec. 31, 2014MMBoe | |
Oil | ||||||
Reserve Quantities [Line Items] | ||||||
Extension and discoveries attributable to successful drilling (in MMBOE) | Boe | 8,424,991 | 10,708,574 | 33,326,267 | |||
Purchase of mineral in place attributable to acquisitions (in MMBOE) | 0.8 | |||||
Decrease to reserves due to revisions of previous estimates | 15,445,439 | 15.4 | 40,202,486 | 40.2 | 10,986,213 | 11 |
Upward (downward) adjustment attributable to lower crude oil and natural gas prices (in MMBOE) | 15.7 | (52.6) | 2.1 | |||
Downward adjustment attributable to removal of undeveloped drilling locations (in MMBOE) | 3.4 | |||||
Upward adjustment attributable to well performance (in MMBOE) | 3.6 | 0.9 | ||||
Downward adjustments attributable to reservoir analysis (in MMBOE) | 12.4 | 9.8 | ||||
Williston Basin | ||||||
Reserve Quantities [Line Items] | ||||||
Extension and discoveries attributable to successful drilling (in MMBOE) | 10.7 | 33.3 | ||||
Williston Basin | Oil | ||||||
Reserve Quantities [Line Items] | ||||||
Extension and discoveries attributable to successful drilling (in MMBOE) | 8.4 |
SUPPLEMENTAL OIL AND GAS INFO77
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Future Net Cash Flows of Proved Reserves (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Extractive Industries [Abstract] | ||||
Future Cash Inflows | $ 1,708,870,912 | $ 2,470,707,712 | $ 7,912,622,500 | |
Future Production Costs | (775,534,832) | (981,256,096) | (2,281,320,000) | |
Future Development Costs | (220,869,664) | (356,401,888) | (1,453,562,125) | |
Future Income Tax Expense | (2,477,353) | (5,740,623) | (1,058,511,086) | |
Future Net Cash Inflows | 709,989,063 | 1,127,309,105 | 3,119,229,289 | |
10% Annual Discount for Estimated Timing of Cash Flows | (330,963,050) | (552,510,342) | (1,713,849,746) | |
Standardized Measure of Discounted Future Net Cash Flows | $ 379,026,013 | $ 574,798,763 | $ 1,405,379,543 | $ 1,224,366,826 |
SUPPLEMENTAL OIL AND GAS INFO78
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Average Sales Prices (Details) | 12 Months Ended | ||
Dec. 31, 2016$ / bbl$ / Mcf | Dec. 31, 2015$ / bbl$ / Mcf | Dec. 31, 2014$ / bbl$ / Mcf | |
Natural Gas | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sale price (in dollars per volume unit) | $ / Mcf | 1.67 | 1.63 | 7.37 |
Oil | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sale price (in dollars per volume unit) | $ / bbl | 35.24 | 42.03 | 83.11 |
SUPPLEMENTAL OIL AND GAS INFO79
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Beginning of Period | $ 574,798,763 | $ 1,405,379,543 | $ 1,224,366,826 |
Sales of Oil and Natural Gas Produced, Net of Production Costs | (98,497,165) | (128,964,023) | (330,395,323) |
Extensions and Discoveries | 59,542,911 | 96,770,078 | 567,026,734 |
Previously Estimated Development Cost Incurred During the Period | 23,271,960 | 114,208,095 | 205,125,299 |
Net Change of Prices and Production Costs | (174,656,448) | (1,384,474,928) | (52,577,882) |
Change in Future Development Costs | 57,481,060 | 235,578,690 | (64,185,447) |
Revisions of Quantity and Timing Estimates | (130,664,183) | (363,975,445) | (326,674,460) |
Accretion of Discount | 57,569,313 | 170,222,344 | 152,128,992 |
Change in Income Taxes | 497,950 | 295,949,531 | (79,196) |
Purchases of Minerals in Place | 9,576,760 | 0 | 0 |
Other | 105,092 | 134,104,878 | 30,644,000 |
End of Period | $ 379,026,013 | $ 574,798,763 | $ 1,405,379,543 |
QUARTERLY RESULTS OF OPERATIO80
QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total Revenues | $ 35,943,626 | $ 45,109,408 | $ 32,014,226 | $ 31,836,236 | $ 56,913,029 | $ 101,156,552 | $ 40,863,194 | $ 76,124,638 | $ 144,903,496 | $ 275,057,413 | $ 595,026,742 |
Gain (Loss) on Derivative Instruments, Net | (11,141,233) | 3,381,564 | (10,522,948) | 3,463,883 | 17,563,910 | 51,366,762 | (22,211,048) | 25,663,283 | (14,818,734) | 72,382,907 | 163,412,615 |
Total Operating Expenses | 33,457,789 | 74,583,046 | 124,946,744 | 141,220,772 | 213,112,194 | 408,323,554 | 343,402,927 | 429,607,005 | 374,208,351 | 1,394,445,680 | 289,855,485 |
Impairment | 0 | 43,820,791 | 88,880,921 | 104,311,122 | 167,143,533 | 354,422,654 | 281,964,097 | 360,428,962 | 237,012,834 | 1,163,959,246 | 0 |
Income (Loss) from Operations | 2,485,837 | (29,473,638) | (92,932,518) | (109,384,536) | (156,199,165) | (307,167,002) | (302,539,733) | (353,482,367) | (229,304,855) | (1,119,388,267) | 305,171,257 |
Other Income (Expense) | (16,218,413) | (16,145,257) | (16,046,144) | (17,181,218) | (16,114,205) | (16,152,574) | (14,387,494) | (11,736,205) | (15,902) | (30,091) | 47,364 |
Income Tax Benefit | (1,402,179) | 0 | 0 | 0 | (50) | (77,544) | (66,866,610) | (135,480,000) | (1,402,179) | (202,424,204) | 99,367,000 |
Net Loss | $ (12,330,397) | $ (45,618,895) | $ (108,978,662) | $ (126,565,754) | $ (172,313,320) | $ (323,242,032) | $ (250,060,617) | $ (229,738,572) | $ (293,493,708) | $ (975,354,541) | $ 163,745,945 |
Net Loss Per Common Share – Basic (in dollars per share) | $ (0.20) | $ (0.74) | $ (1.78) | $ (2.08) | $ (2.84) | $ (5.33) | $ (4.12) | $ (3.79) | $ (4.80) | $ (16.08) | $ 2.70 |
Net Loss Per Common Share – Diluted (in dollars per share) | $ (0.20) | $ (0.74) | $ (1.78) | $ (2.08) | $ (2.84) | $ (5.33) | $ (4.12) | $ (3.79) | $ (4.80) | $ (16.08) | $ 2.69 |