Northern Oil and Gas (NOG) 10-Q 8 Nov 13 2013 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 01, 2013
Document and Entity Information [Abstract]	'	'
Entity Registrant Name	'NORTHERN OIL & GAS, INC.	'
Entity Central Index Key	'0001104485	'
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	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	61,804,666
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'

BALANCE_SHEETS_UNAUDITED

BALANCE SHEETS (UNAUDITED) (USD $)	Sep. 30, 2013	Dec. 31, 2012
CURRENT ASSETS	'	'
Cash and Cash Equivalents	$11,868,598	$13,387,998
Trade Receivables	92,201,013	70,219,669
Advances to Operators	1,666,129	3,109,591
Prepaid Expenses and Other	2,160,026	1,707,089
Derivative Instruments	22,692	4,095,197
Deferred Tax Asset	10,896,000	1,695,000
Total Current Assets	118,814,458	94,214,544
Oil and Natural Gas Properties, Full Cost Method of Accounting	'	'
Proved	1,476,511,245	1,159,191,601
Unproved	85,059,046	82,926,384
Other Property and Equipment	1,567,652	3,158,224
Total Property and Equipment	1,563,137,943	1,245,276,209
Less - Accumulated Depreciation and Depletion	-247,019,968	-162,031,493
Total Property and Equipment, Net	1,316,117,975	1,083,244,716
DERIVATIVE INSTRUMENTS	934,545	1,763,008
DEBT ISSUANCE COSTS NET	16,868,802	11,713,030
TOTAL ASSETS	1,452,735,780	1,190,935,298
CURRENT LIABILITIES	'	'
Accounts Payable	146,468,743	95,822,162
Accrued Expenses	3,493,161	2,454,085
Accrued Interest	13,333,333	2,180,416
Derivative Instruments	21,841,508	0
Total Current Liabilities	185,136,745	100,456,663
LONG-TERM LIABILITIES	'	'
Revolving Credit Facility	45,000,000	124,000,000
8% Senior Notes, net of accumulated amortization of bond premium of $588,496 at September 30, 2013 and $0 at December 31, 2012	509,911,504	300,000,000
Derivative Instruments	3,059,416	2,547,745
Other Noncurrent Liabilities	2,129,018	1,570,630
Deferred Tax Liability	106,634,000	76,175,000
Total Long-Term Liabilities	666,733,938	504,293,375
TOTAL LIABILITIES	851,870,683	604,750,038
COMMITMENTS AND CONTINGENCIES (NOTE 8)	'	'
STOCKHOLDERS' EQUITY	'	'
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding	0	0
Common Stock, Par Value $.001; 95,000,000 Authorized, (9/30/2013 - 61,796,675 Shares Outstanding and 12/31/2012 - 63,532,622 Shares Outstanding)	61,797	63,532
Additional Paid-In Capital	444,481,894	465,466,420
Retained Earnings	156,321,406	120,655,308
Total Stockholders' Equity	600,865,097	586,185,260
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$1,452,735,780	$1,190,935,298

BALANCE_SHEETS_UNAUDITED_Paren

BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Liabilities, Noncurrent [Abstract]	'	'
Accumulated amortization of bond premium	$588,496	$0
STOCKHOLDERS' EQUITY	'	'
Preferred Stock, par value (in dollars per share)	$0.00	$0.00
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)	$0.00	$0.00
Common Stock, shares authorized (in shares)	95,000,000	95,000,000
Common Stock, shares outstanding (in shares)	61,796,675	63,532,622

STATEMENTS_OF_COMPREHENSIVE_IN

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
REVENUES	'	'	'	'
Oil and Gas Sales	$107,232,064	$80,690,301	$270,026,894	$216,268,712
(Loss) Gain on Settled Derivatives	-8,096,075	1,701,296	-8,966,175	-4,729,186
Unrealized Gain (Loss) on Derivative Instruments	-29,353,161	-22,308,470	-27,254,147	18,125,928
Other Revenue	1,372	12,486	37,514	160,752
Total Revenues	69,784,200	60,095,613	233,844,086	229,826,206
OPERATING EXPENSES	'	'	'	'
Production Expenses	11,471,867	8,734,636	30,510,248	22,540,237
Production Taxes	9,931,345	8,092,843	25,303,805	20,829,732
General and Administrative Expense	4,164,335	9,467,711	12,068,439	18,568,696
Depletion, Depreciation, Amortization and Accretion	32,103,607	28,081,124	85,455,425	72,147,282
Total Expenses	57,671,154	54,376,314	153,337,917	134,085,947
INCOME FROM OPERATIONS	12,113,046	5,719,299	80,506,169	95,740,259
OTHER INCOME (EXPENSE)	'	'	'	'
Interest Expense, Net of Capitalization	-9,212,834	-5,205,822	-23,140,425	-8,130,225
Other (Expense) Income	-169,308	106	-437,032	1,206
Total Other Income (Expense)	-9,382,142	-5,205,716	-23,577,457	-8,129,019
INCOME BEFORE INCOME TAXES	2,730,904	513,583	56,928,712	87,611,240
INCOME TAX PROVISION	1,028,000	213,422	21,262,614	34,878,772
NET INCOME	1,702,904	300,161	35,666,098	52,732,468
OTHER COMPREHENSIVE INCOME NET OF TAX	'	'	'	'
Reclassification of Derivative Instruments Included in Income (Net of Tax of $39,000 for the Nine Months ended September 30,2012,)	0	0	0	62,309
Total Other Comprehensive Income (Loss)	0	0	0	62,309
COMPREHENSIVE INCOME	$1,702,904	$300,161	$35,666,098	$52,794,777
Net Income Per Common Share - Basic (in dollars per share)	$0.03	$0	$0.57	$0.84
Net Income Per Common Share - Diluted (in dollars per share)	$0.03	$0	$0.56	$0.84
Weighted Average Shares Outstanding - Basic (in shares)	62,426,341	62,589,256	62,750,952	62,410,110
Weighted Average Shares Outstanding - Diluted (in shares)	62,758,378	62,882,673	63,142,238	62,753,241

STATEMENTS_OF_COMPREHENSIVE_IN1

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $)	9 Months Ended
	Sep. 30, 2012
COMPREHENSIVE INCOME, NET OF TAX	'
Reclassification of Derivative Instruments Included in Income, Tax	$39,000

STATEMENTS_OF_CASH_FLOWS_UNAUD

STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net Income	$35,666,098	$52,732,468
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:	'	'
Depletion, Depreciation, Amortization and Accretion	85,455,425	72,147,282
Amortization of Debt Issuance Costs	1,867,482	1,025,009
Amortization of Senior Unsecured Notes Premium	-588,496	0
Deferred Income Taxes	21,258,000	34,870,000
Unrealized (Gain) Loss on Derivative Instruments	27,254,147	-18,125,928
Amortization of Deferred Rent	-15,876	-24,921
Share - Based Compensation Expense	3,547,493	11,295,664
Changes in Working Capital and Other Items:	'	'
Trade Receivables	-21,981,344	-27,906,153
Prepaid Expenses and Other	116,003	-234,647
Accounts Payable	6,026,364	-723,549
Accrued Interest	9,274,841	8,923,869
Accrued Expenses	1,039,076	2,717,838
Net Cash Provided By Operating Activities	168,919,213	136,696,932
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Purchases of Oil and Gas Properties and Development Capital Expenditures	-269,390,319	-419,687,257
Proceeds from Sale of Oil and Gas Properties	908,000	0
Purchases of Other Equipment and Furniture	-255,603	-185,157
Net Cash Used For Investing Activities	-268,737,922	-419,872,414
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Advances on Revolving Credit Facility	103,000,000	409,600,000
Repayments on Revolving Credit Facility	-182,000,000	-411,500,000
Issuance of Senior Unsecured Notes	210,500,000	300,000,000
Debt Issuance Costs Paid	-7,023,254	-11,850,614
Repurchase of Common Stock	-26,177,437	-1,173,315
Proceeds from Exercise of Stock Options	0	54,390
Net Cash Provided by Financing Activities	98,299,309	285,130,461
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	-1,519,400	1,954,979
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD	13,387,998	6,279,587
CASH AND CASH EQUIVALENTS - END OF PERIOD	11,868,598	8,234,566
Supplemental Disclosure of Cash Flow Information	'	'
Cash Paid During the Period for Interest	15,196,809	2,226,598
Cash Paid During the Period for Income Taxes	13,614	8,772
Non-Cash Financing and Investing Activities:	'	'
Oil and Natural Gas Properties Included in Accounts Payable	136,396,330	118,873,584
Capitalized Asset Retirement Obligations	476,549	413,146
Non-Cash Compensation Capitalized on Oil and Gas Properties	$1,643,683	$5,834,242

ORGANIZATION_AND_NATURE_OF_BUS

ORGANIZATION AND NATURE OF BUSINESS	9 Months Ended
	Sep. 30, 2013
ORGANIZATION AND NATURE OF BUSINESS [Abstract]	'
ORGANIZATION AND NATURE OF BUSINESS	'
	NOTE 1 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 September 30, 2013, approximately 55% of Northern's 186,947 total net acres were developed.

SIGNIFICANT_ACCOUNTING_POLICIE

SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2013

SIGNIFICANT ACCOUNTING POLICIES [Abstract]

'

SIGNIFICANT ACCOUNTING POLICIES

'

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

The financial information included herein is unaudited, except for the balance sheet as of December 31, 2012, which has been derived from the Company's audited financial statements for the year ended December 31, 2012. However, such information includes all adjustments (consisting of normal recurring adjustments and change in accounting principles) that are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.

Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission ("SEC"). The financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2012, which were included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

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, and deferred income taxes. Actual results may differ from those estimates.

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.

The allowance for doubtful accounts at September 30, 2013 and December 31, 2012 was $925,000 and $0, respectively.

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 $61,485 and $104,830 for the three months ended September 30, 2013 and 2012, respectively. Depreciation expense was $248,626 and $304,226 for the nine months ended September 30, 2013 and 2012, respectively.

Full Cost Method

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 three and nine months ended September 30, 2013 and 2012, respectively.

Three Months Ended

Nine Months Ended

September 30,

September 30,

2013

2012

2013

2012

Capitalized Certain Payroll and Other Internal Costs

$

894,573

$

79,471

$

2,257,022

$

7,366,101

Capitalized Interest Costs

1,597,129

1,811,088

4,525,906

4,426,429

Total

$

2,491,702

$

1,890,559

$

6,782,928

$

11,792,530

As of September 30, 2013, 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. There were no property sales in the nine months ended September 30, 2013 and 2012.

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 based on the estimated gross proved reserves as determined by independent petroleum engineers. 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 three months ended September 30, 2013 and 2012, the Company transferred into the full cost pool costs related to expired leases of $3.3 million and $0.5 million, respectively. For the nine months ended September 30, 2013 and 2012, the Company transferred into the full cost pool costs related to expired leases of $11.3 million and $3.1 million, respectively.

Capitalized costs of crude oil and natural gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved crude oil and natural gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the 12-month average price of crude oil and natural gas to estimated future production of proved crude oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense. As of September 30, 2013 and December 31, 2012, the Company has not realized any impairment of its properties.

Asset Retirement Obligations

Asset retirement obligation is included in other noncurrent liabilities and relates to future costs associated with the plugging and abandonment of crude oil and natural gas wells, removal of equipment and facilities from leased acreage and returning the land to its original condition. Estimates are based on estimated remaining lives of those wells based on reserve estimates, external estimates to plug and abandon the wells in the future, inflation, credit adjusted discount rates and federal and state regulatory requirements. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.

Debt Issuance Costs

At September 30, 2013, the Company had capitalized debt issuance costs of $5.9 million in connection with the revolving credit facility and $14.3 million in connection with the "8% Senior Notes Due 2020" (see Note 4). 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.

The amortization of debt issuance costs for the three months ended September 30, 2013 and 2012 was $706,602 and $492,745, respectively. The amortization of debt issuance costs for the nine months ended September 30, 2013 and 2012 was $1,867,482 and $1,025,009, respectively.

Bond Premium on Senior Notes

At September 30, 2013, the Company had 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 for the three months ended September 30, 2013 and 2012 was $371,681 and $0, respectively. The amortization of the bond premium for the nine months ended September 30, 2013 and 2012 was $588,496 and $0, 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 September 30, 2013 and December 31, 2012, 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. Trade receivables are generally not collateralized.

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 customers 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.

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. 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.

Income Taxes

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. 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. No valuation allowance has been recorded as of September 30, 2013 and December 31, 2012.

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 three and nine months ended September 30, 2013 and 2012 are as follows:

Three Months Ended

Nine Months Ended

September 30,

September 30,

2013

2012

2013

2012

Weighted average common shares outstanding – basic

62,426,341

62,589,256

62,750,952

62,410,110

Plus: Potentially dilutive common shares

Stock options and restricted stock

332,037

293,417

391,286

343,131

Weighted average common shares outstanding – diluted

62,758,378

62,882,673

63,142,238

62,753,241

Restricted stock excluded from EPS due to the anti-dilutive effect

2,290

34,702

9,295

23,099

As of September 30, 2013 and 2012, potentially dilutive shares from stock options were 251,963.

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.

On November 1, 2009, due to the volatility of price differentials in the Williston Basin, the Company de-designated all derivatives that were previously classified as cash flow hedges and in addition, the Company has elected not to designate any subsequent derivative contracts as accounting hedges. As such, all derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses are recorded to gain (loss) on settled derivatives and unrealized gains or losses are recorded to gain (loss) on mark-to-market of derivative instruments on the statements of comprehensive income rather than as a component of accumulated other comprehensive income (loss) or other income (expense). See Note 12 for a description of the derivative contracts which the Company has entered into.

Prior to November 1, 2009, the Company, at the inception of a derivative contract, designated the derivative as a cash flow hedge. For all derivatives designated as cash flow hedges, the Company formally documented the relationship between the derivative contract and the hedged items, as well as the risk management objective for entering into the derivative contract. To be designated as a cash flow hedge transaction, the relationship between the derivative and the hedged items must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis. The Company historically measured hedge effectiveness on a quarterly basis and hedge accounting would be discontinued prospectively if it determined that the derivative was no longer effective in offsetting changes in the cash flows of the hedged item. Gains and losses deferred in accumulated other comprehensive income (loss) related to cash flow hedge derivatives that become ineffective remain unchanged until the related production was delivered. If the Company determined that it was probable that a hedged forecasted transaction would not occur, deferred gains or losses on the derivative were recognized in earnings immediately.

Derivatives, historically, were recorded on the balance sheet at fair value and changes in the fair value of derivatives were recorded each period in current earnings or other comprehensive income (loss), depending on whether a derivative was designated as part of a hedge transaction and, if it was, depending on the type of hedge transaction. The Company's derivatives historically consisted primarily of cash flow hedge transactions in which the Company was hedging the variability of cash flows related to a forecasted transaction. Period to period changes in the fair value of derivative instruments designated as cash flow hedges were reported in accumulated other comprehensive income (loss) and reclassified to earnings in the periods in which the hedged item impacts earnings. The ineffective portion of the cash flow hedges were reflected in current period earnings as gain or loss from derivatives. Gains and losses on derivative instruments that did not qualify for hedge accounting were included in income or loss from derivatives in the period in which they occur. The resulting cash flows from derivatives were reported as cash flows from operating activities.

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 (which the Company uses) are excluded from this requirement but continue to be subject to the full cost method's impairment rules. There was no impairment recorded for the three months and nine months ended September 30, 2013 and 2012.

New Accounting Pronouncements

From time to time, new accounting pronouncements are issued by 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.

Recently Adopted

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity's financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. In January 2013, the FASB issued Balance Sheet (Topic 210) — Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures. These disclosure requirements do not affect the presentation of amounts in the balance sheets, and were effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual reporting periods.

CRUDE_OIL_AND_NATURAL_GAS_PROP

CRUDE OIL AND NATURAL GAS PROPERTIES	9 Months Ended
	Sep. 30, 2013
CRUDE OIL AND NATURAL GAS PROPERTIES [Abstract]	'
CRUDE OIL AND NATURAL GAS PROPERTIES	'
	NOTE 3 CRUDE OIL AND NATURAL GAS PROPERTIES
	The value of the Company's crude oil and natural gas properties consists of all acreage 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 comprehensive income 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. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of equity securities. Purchases of properties and development capital expenditures that were in accounts payable and not yet paid in cash at September 30, 2013 and December 31, 2012 were approximately $136.4 million and $91.8 million, respectively.
	Acquisitions
	For the nine months ended September 30, 2013, the Company acquired approximately 17,854 net mineral acres, for an average cost of approximately $1,234 per net acre, in its key prospect areas in the form of effective leases. During the same period, the Company separately acquired working interests in 56 gross (5.5 net) wells, in which it does not hold the underlying leasehold interests, for a total cost of approximately $7.3 million (which excludes the estimated drilling and completion costs for these wells).
	For the nine months ended September 30, 2012, the Company acquired or earned through farm-in arrangements approximately 21,153 net mineral acres, for an average cost of approximately $1,913 per net acre, in its key prospect areas in the form of effective leases.
	Unproved Properties
	Unproved properties not being amortized comprise approximately 64,500 net acres of undeveloped leasehold interests at September 30, 2013 and December 31, 2012. 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.
	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. At September 30, 2013 and December 31, 2012, the amounts of capitalized costs excluded from depletion were $85.1 million and $82.9 million, respectively.
	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, with the exception of the defined drilling projects with Slawson Exploration Company, Inc. described below.
	As of September 30, 2013, the Company was participating in three defined drilling projects with Slawson Exploration Company, Inc., with participation interests ranging between 4.5% and 50%, covering an aggregate of approximately 19,600 net acres of leasehold interests held by the Company. The areas cover the Windsor project area (4.5% participation interest), which includes approximately 2,100 net acres held by the Company, primarily located in Mountrail and surrounding counties of North Dakota. The South West Big Sky project (20% participation interest) includes approximately 5,500 total net acres held by the Company in Richland County, Montana. The Lambert project (50% participation interest) includes approximately 12,000 net acres held by the Company in Richland County, Montana.

REVOLVING_CREDIT_FACILITY_AND_

REVOLVING CREDIT FACILITY AND LONG TERM DEBT	9 Months Ended
	Sep. 30, 2013
REVOLVING CREDIT FACILITY AND LONG TERM DEBT [Abstract]	'
REVOLVING CREDIT FACILITY AND LONG TERM DEBT	'
	NOTE 4 REVOLVING CREDIT FACILITY AND LONG-TERM DEBT
	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 September 30, 2013, the facility amount was $750 million, the borrowing base was $450 million and there was a $45 million outstanding balance, leaving $405 million of borrowing capacity available under the facility. Under the terms of the Revolving Credit Facility, the Company may issue an unlimited amount of permitted additional indebtedness, as defined, provided that the borrowing base will be reduced by 25% of the stated amount of any such permitted additional indebtedness. The $500 million in Notes described below is "permitted additional indebtedness" as defined in the Revolving Credit 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 event-driven unscheduled redeterminations. Borrowings under the Revolving Credit Facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.5% to 1.5% or LIBOR borrowings at the Adjusted LIBOR Rate (as defined) plus a spread ranging from 1.5% to 2.5%. 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 September 30, 2013, the commitment fee was 0.375% and the interest rate margin was 1.5% on LIBOR loans and 0.5% on base rate loans.
	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, or make investments. 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. The Company was in compliance with its covenants under the Revolving Credit Facility at September 30, 2013.
	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% an additional $200 million aggregate principal amount of 8.000% senior unsecured notes due June 1, 2020 (the "Follow-on Notes" and, together with the Original 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 and the issuance of the Follow-on Notes resulted in net proceeds to the Company of approximately $200.1 million, which 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).
	At any time prior to June 1, 2015, the Company may redeem up to 35% of the Notes at a redemption price of 108% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings, so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to June 1, 2016, the Company may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. 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 Notes are governed by an Indenture (the "Indenture"), dated as of May 18, 2012, by and among the Company and Wilmington Trust, National Association, as trustee (the "Trustee").
	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 important 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 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 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	9 Months Ended
	Sep. 30, 2013
COMMON AND PREFERRED STOCK [Abstract]	'
COMMON AND PREFERRED STOCK	'
	NOTE 5 COMMON AND PREFERRED STOCK
	The Company's Articles of Incorporation authorize the issuance of up to 100,000,000 shares. The shares are classified in two classes, consisting of 95,000,000 shares of common stock, par value $.001 per share, and 5,000,000 shares of preferred stock, par value $.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 common stock during the nine months ended September 30, 2013 and the year ended December 31, 2012:
		Nine Months Ended			Year Ended
		30-Sep-13			31-Dec-12
	Beginning Balance		63,532,622			63,330,421
	Stock Based Compensation		43,029			-
	Stock Options Exercised		-			10,500
	Restricted Stock Grants (Note 6)		299,401			890,379
	Stock Repurchased		(2,036,383	)		-
	Other Surrenders		(41,994	)		(698,678	)
	Ending balance		61,796,675			63,532,622
	2013 Activity
	The Company's Chief Executive Officer receives shares of common stock as compensation in lieu of any cash base salary. For the nine months ended September 30, 2013, the Company issued 43,029 shares valued at $608,430 to the Chief Executive Officer as compensation in lieu of any cash base salary.
	In the nine months ended September 30, 2013, 4,297 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 $64,000, which was based on the market price on the date the shares were surrendered.
	In the nine months ended September 30, 2013, 37,697 shares of restricted common stock were surrendered by employees who terminated employment with the Company.
	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.
	During the third quarter of 2013, the Company repurchased 2,036,383 shares of its common stock under the stock repurchase program. These shares are now included in the Company's pool of authorized but unissued shares. This stock had a cost of approximately $26.1 million. 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_OPTIONSSTOCKBASED_COMPEN

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS	9 Months Ended
	Sep. 30, 2013
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS [Abstract]	'
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS	'
	NOTE 6 STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS
	On April 5, 2013, the board of directors approved the Company's 2013 Incentive Plan (the "2013 Plan"), which was subsequently approved at the 2013 annual meeting of shareholders. 1,500,000 shares were authorized for grant under the 2013 Plan, plus the number of shares remaining available for future grants under the Company's predecessor 2009 Equity Incentive Plan on the date the shareholders approved the 2013 Plan. The 2013 Plan is intended 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.
	Restricted Stock Awards
	During the nine months ended September 30, 2013, the Company issued 299,401 restricted shares of common stock 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 February 2017. As of September 30, 2013, there was approximately $6.2 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense will be recognized over the remaining vesting period of the grants. The Company has assumed a zero percent forfeiture rate 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 nine months ended September 30, 2013:
		Nine Months Ended
		30-Sep-13
		Number of			Weighted-Average
		Shares			Price
	Restricted Stock Awards:
	Restricted Shares Outstanding at the Beginning of Period		777,437			$	18.93
	Shares Granted		299,401				15.38
	Shares Forfeited		(37,697	)			16.85
	Lapse of Restrictions		(361,103	)			19.15
	Restricted Shares Outstanding at September 30, 2013		678,038			$	17.37
	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 September 30, 2013, options to purchase a total of 251,963 shares remain outstanding but unexercised. The board of directors determined that no future grants will be made pursuant to the 2006 Incentive Stock Option Plan. All future stock compensation will be issued under the 2013 Plan.
	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. 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 the nine months ended September 30, 2013.
	Currently Outstanding Options
	·	No options were forfeited in the nine month period ended September 30, 2013.
	·	No options expired during the nine month period ended September 30, 2013.
	·	Options covering 251,963 shares were exercisable and outstanding at September 30, 2013.
	·	There is no further compensation expense that will be recognized in future periods relative to any options that had been granted as of September 30, 2013, because the Company recognized the entire fair value of such compensation upon vesting of the options.
	·	There were no unvested options at September 30, 2013.

RELATED_PARTY_TRANSACTIONS

RELATED PARTY TRANSACTIONS	9 Months Ended
	Sep. 30, 2013
RELATED PARTY TRANSACTIONS [Abstract]	'
RELATED PARTY TRANSACTIONS	'
	NOTE 7 RELATED PARTY TRANSACTIONS
	Carter Stewart, a former director of the Company (until August 2011), owned a 25% interest in Gallatin Resources, LLC ("Gallatin"). Legal counsel for Gallatin informed the Company that Mr. Stewart did not have the power to control Gallatin because each member of Gallatin has the right to vote on matters in proportion to their respective membership interest in the company and company matters are determined by a vote of the holders of a majority of membership interests. Further, Mr. Stewart was neither an officer nor a director of Gallatin. As such, Mr. Stewart did not have the ability to individually control company decisions for Gallatin. In 2012, the Company paid Gallatin a total of approximately $500 related to previously acquired leasehold interests. There were no payments to related parties for the nine months ended September 30, 2013.
	All transactions involving related parties were approved by the Company's board of directors or Audit Committee.

COMMITMENTS_CONTINGENCIES

COMMITMENTS & CONTINGENCIES	9 Months Ended
	Sep. 30, 2013
COMMITMENTS & CONTINGENCIES [Abstract]	'
COMMITMENTS & CONTINGENCIES	'
	NOTE 8 COMMITMENTS & CONTINGENCIES
	Litigation
	The Company is engaged in 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 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 is party to a quiet title action in North Dakota that relates to its interest in certain crude oil and natural gas leases. In the event the action results in a final judgment that is adverse to the Company, the Company would be required to reverse approximately $1.5 million in revenue (net of accrued taxes) that has been accrued since the second quarter of 2008 based on the Company's purported interest in the crude oil and natural gas leases at issue, $0.2 million of which relates to the nine month period ended September 30, 2013. The Company fully maintains the validity of its interest in the crude oil and natural gas leases, and is vigorously defending such interest.

INCOME_TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2013
INCOME TAXES [Abstract]	'
INCOME TAXES	'
	NOTE 9 INCOME TAXES
	The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
	In 2013, the State of North Dakota lowered its corporate income tax rate. The impact of this rate change was to lower the Company's deferred state income tax expense by approximately $0.5 million in the nine month period ended September 30, 2013.
	The income tax provision for the three and nine months ended September 30, 2013 and 2012 consists of the following:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
	Current Income Taxes	$	-	$	3,422	$	4,614	$	8,772
	Deferred Income Taxes
	Federal		956,000		175,000		19,925,000		30,660,000
	State		72,000		35,000		1,333,000		4,210,000
	Total Provision	$	1,028,000	$	213,422	$	21,262,614	$	34,878,772
	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 three and nine months ended September 30, 2013 and 2012, the Company did not recognize any interest or penalties in its statements of comprehensive income nor did it have any interest or penalties accrued in its balance sheet at September 30, 2013 and December 31, 2012 relating to unrecognized benefits.
	The tax years 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.

FAIR_VALUE

FAIR VALUE	9 Months Ended
	Sep. 30, 2013
FAIR VALUE [Abstract]	'
FAIR VALUE	'
	NOTE 10 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 of 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.
	The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the balance sheet as of September 30, 2013 and December 31, 2012.
		Fair Value Measurements at
		September 30, 2013 Using
		Quoted Prices In Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
		(Level 1)		(Level 2)			(Level 3)
	Commodity Derivatives – Current Asset (crude oil swaps and collars)	$	-	$	22,692		$	-
	Commodity Derivatives – Current Liability (crude oil swaps and collars)		-		(21,841,508	)		-
	Commodity Derivatives – Non- Current Asset (crude oil swaps and collars)		-		934,545			-
	Commodity Derivatives – Non- Current Liability (crude oil swaps and collars)		-		(3,059,416	)		-
	Total	$	-	$	(23,943,687	)	$	-
		Fair Value Measurements at
		December 31, 2012 Using
		Quoted Prices In Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
		(Level 1)		(Level 2)			(Level 3)
	Commodity Derivatives – Current Asset (crude oil swaps and collars)	$	-	$	4,095,197		$	-
	Commodity Derivatives – Non-Current Asset (crude oil swaps and collars)		-		1,763,008			-
	Commodity Derivatives – Non-Current Liability (crude oil swaps and collars)		-		(2,547,745	)		-
	Total	$	-	$	3,310,460		$	-
	Level 2 assets and liabilities consist of derivative assets and liabilities (see Note 12), the Revolving Credit Facility (see Note 4) and the Notes (see Note 4). The fair value of the Company's derivative financial instruments is determined based upon futures 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 year. The book value of the Revolving Credit Facility approximates fair value because of its floating rate structure. The fair value of our 8% senior notes is based on an end of period market quote.
	The Company's long-term debt is not measured at fair value on the balance sheets and the fair value is being provided for disclosure purposes. At September 30, 2013, the Company had $500 million of senior unsecured notes and $45.0 million under the Revolving Credit Facility outstanding, with a fair value of $501 million and $45.0 million, respectively. At December 31, 2012, the Company had $300 million of senior unsecured notes and $124.0 million under the Revolving Credit Facility outstanding, with a fair value of $310.5 million and $124.0 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable inputs regarding interest rates available to the Company at the end of each respective period.
	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 nine month period ended September 30, 2013.

FINANCIAL_INSTRUMENTS

FINANCIAL INSTRUMENTS	9 Months Ended
	Sep. 30, 2013
FINANCIAL INSTRUMENTS [Abstract]	'
FINANCIAL INSTRUMENTS	'
	NOTE 11 FINANCIAL INSTRUMENTS
	The Company's non-derivative financial instruments include cash and cash equivalents, and credit facility and are not measured at fair value on the balance sheets. The carrying amount of these non-derivative financial instruments approximate their fair values (See Note 10).
	The Company's accounts receivable relate to crude oil and natural gas sold to various industry companies. Credit terms, typical of industry standards, are of a short-term nature and the Company does not require collateral. Management believes the Company's accounts receivable at September 30, 2013 and December 31, 2012 do not represent significant credit risks as they are dispersed across many counterparties. The Company has recorded an allowance for doubtful accounts of $925,000 and $0 at September 30, 2013 and December 31, 2012, respectively. As of September 30, 2013, outstanding derivative contracts with commercial banks participating in the Company's revolving credit facility represent all of the Company's crude oil volumes hedged. These commercial banks have investment-grade ratings from Moody's and Standard & Poor and are lenders under the Company's revolving credit facility and management believes this does not represent a significant credit risk.

DERIVATIVE_INSTRUMENTS_AND_PRI

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT	9 Months Ended
	Sep. 30, 2013
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT [Abstract]	'
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT	'
	NOTE 12 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT
	The Company utilizes commodity swap contracts and costless 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.
	On November 1, 2009, due to the volatility of price differentials in the Williston Basin, the Company de-designated all derivatives that were previously classified as cash flow hedges and, in addition, the Company has elected not to designate any subsequent derivative contracts as cash flow hedges. Beginning on November 1, 2009, all derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses are recorded to loss on settled derivatives and unrealized gains or losses are recorded to unrealized gain (loss) on derivative instruments on the statement of comprehensive income rather than as a component of other comprehensive income (loss) or other income (expense).
	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.
	Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges
	The Company had a realized (loss) gain on settled derivatives of $(8,096,075) and $1,701,296 for the three months ended September 30, 2013 and 2012, respectively. The Company had an unrealized loss on mark-to-market of derivative instruments of $29,353,161 and $22,308,470 for the three months ended September 30, 2013 and 2012, respectively. The Company had a realized loss on settled derivatives of $8,966,175 and $4,729,186 for the nine months ended September 30, 2013 and 2012, respectively. The Company had an unrealized (loss) gain on mark-to-market of derivative instruments of $(27,254,147) and $18,125,928 for the nine months ended September 30, 2013 and 2012, respectively.
	The following table reflects open commodity swap contracts as of September 30, 2013, the associated volumes and the corresponding fixed price.
	Settlement Period		Oil (Barrels)				Fixed Price
	Swaps-Crude Oil
	10/01/13 – 12/31/14			300,000			$	91.65
	10/01/13 – 12/31/13			120,000				89.5
	10/01/13 – 12/31/13			60,000				91.1
	10/01/13 – 12/31/13			30,000				94.5
	10/01/13 – 12/31/13			30,000				102.3
	10/01/13 – 12/31/13			30,000				94.5
	10/01/13 – 12/31/14			356,250				88.55
	10/01/13 – 12/31/14			356,250				88.6
	10/01/13 – 12/31/14			356,250				88.4
	10/01/13 – 12/31/14			356,250				88.5
	10/01/13 – 06/30/15			510,000				89.15
	10/01/13 – 12/31/15			810,000				89
	01/01/14 – 06/30/14			300,000				89.5
	01/01/14 – 06/30/14			240,000				90
	01/01/14 – 06/30/14			240,000				100
	01/01/14 – 12/31/14			120,000				91.35
	01/01/14 – 12/31/14			120,000				90
	01/01/14 – 12/31/14			240,000				90.15
	01/01/14 – 12/31/14			240,000				91
	01/01/14 – 12/31/14			120,000				93
	07/01/14 – 12/31/14			120,000				90
	07/01/14 – 12/31/14			120,000				90
	07/01/14 – 12/31/14			120,000				93.5
	07/01/14 – 12/31/14			30,000				90.58
	01/01/15 – 06/30/15			60,000				90.5
	01/01/15 – 06/30/15			180,000				88.55
	01/01/15 – 06/30/15			180,000				88
	01/01/15 – 06/30/15			60,000				90.75
	01/01/15 – 06/30/15			60,000				90.25
	01/01/15 – 12/31/15			360,000				89
	01/01/15 – 12/31/15			360,000				89.02
	01/01/15 – 12/31/15			180,000				89
	01/01/15 – 12/31/15			180,000				89
	As of September 30, 2013, the Company had a total volume on open commodity swaps of 6.9 million barrels at a weighted average price of approximately $89.95.
	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 September 30, 2013.
	Term		Oil (Barrels)				Floor/Ceiling Price			Basis
	Costless Collars – Crude Oil
	10/01/13 – 12/31/13			32,187			$	90.00/$103.50		NYMEX
	10/01/13 – 12/31/13			28,481			$	90.00/$106.50		NYMEX
	10/01/13 – 12/31/13			49,412			$	90.00/$110.00		NYMEX
	10/01/13 – 12/31/13			39,737			$	95.00/$107.00		NYMEX
	10/01/13 – 12/31/13			120,000			$	95.00/$110.70		NYMEX
	10/01/13 – 12/31/13			170,047			$	85.00/$98.00		NYMEX
	10/01/13 – 12/31/13			30,000			$	90.25/$97.95		NYMEX
	10/01/13 – 12/31/13			48,000			$	95.00/$106.90		NYMEX
	10/01/13 – 12/31/13			15,000			$	93.00/$100.00		NYMEX
	01/01/14 – 12/31/14			240,000			$	90.00/$99.05		NYMEX
	The following table sets forth the amounts, on a gross basis, and classification of the Company's outstanding derivative financial instruments at September 30, 2013 and December 31, 2012, 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:
	Type of Contract	Balance Sheet Location		30-Sep-13				31-Dec-12
				Estimated Fair Value				Estimated Fair Value
	Derivative Assets:
	Swap Contracts	Current Assets/Liabilities		$	619,662			$	680,647
	Swap Contracts	Non-Current Assets			1,863,580				1,977,722
	Costless Collars	Current Assets/Liabilities			60,860				11,769,415
Costless Collars	Non-Current Assets/Liabilities			120,398				5,629,996
Total Derivative Assets			$	2,664,500			$	20,057,780
Derivative Liabilities:
Swap Contracts	Current Assets/Liabilities		$	(21,336,245	)		$	(2,037,070	)
Swap Contracts	Non-Current Assets/Liabilities			(4,108,849	)			(3,170,945	)
Costless Collars	Current Assets/Liabilities			(1,163,093	)			(6,317,795	)
Costless Collars	Non-Current Liabilities			-				(5,221,510	)
Total Derivative Liabilities			$	(26,608,187	)		$	(16,747,320	)
The following disclosures are applicable to the Company's financial statements, as of September 30, 2013 and 2012, respectively:
			Amount of Loss Reclassified from
			AOCI into Income
			Three Months Ended								Nine Months Ended
			September 30,								September 30,
Derivative Type	Location of Loss		2013				2012				2013		2012
	for Effective and
	Ineffective
	Portion of Derivative
	In Income
Commodity - Cash Flow	Loss on Settled Derivatives		$	-			$	-			$	-	$	101,309
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 September 30, 2013
	Gross Amounts of Recognized Assets				Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
Offsetting of Derivative Assets:
Current Assets		$	680,522			$	(657,830	)		$	22,692
Non-Current Assets			1,983,978				(1,049,433	)			934,545
Total Derivative Assets		$	2,664,500			$	(1,707,263	)		$	957,237
Offsetting of Derivative Liabilities:
Current Liabilities		$	(22,499,338	)		$	657,830			$	(21,841,508	)
Non-Current Liabilities			(4,108,849	)			1,049,433				(3,059,416	)
Total Derivative Liabilities		$	(26,608,187	)		$	1,707,263			$	(24,900,924	)
	Estimated Fair Value at December 31, 2012
	Gross Amounts of Recognized Assets				Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
Offsetting of Derivative Assets:
Current Assets		$	12,450,062			$	(8,354,865	)		$	4,095,197
Non-Current Assets			7,607,719				(5,844,711	)			1,763,008
Total Derivative Assets		$	20,057,781			$	(14,199,576	)		$	5,858,205
Offsetting of Derivative Liabilities:
Current Liabilities		$	(8,354,865	)		$	8,354,865			$	-
Non-Current Liabilities			(8,392,456	)			5,844,711				(2,547,745	)
Total Derivative Liabilities		$	(16,747,321	)		$	14,199,576			$	(2,547,745	)

SUBSEQUENT_EVENTS

SUBSEQUENT EVENTS	9 Months Ended
	Sep. 30, 2013
SUBSEQUENT EVENTS [Abstract]	'
SUBSEQUENT EVENTS	'
	NOTE 13 SUBSEQUENT EVENTS
	In connection with preparing the unaudited financial statements for the nine months ended September 30, 2013, 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.

SIGNIFICANT_ACCOUNTING_POLICIE1

SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2013

SIGNIFICANT 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, and deferred income taxes. Actual results may differ from those estimates.

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.

The allowance for doubtful accounts at September 30, 2013 and December 31, 2012 was $925,000 and $0, respectively.

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. Depreciation expense was $61,485 and $104,830 for the three months ended September 30, 2013 and 2012, respectively. Depreciation expense was $248,626 and $304,226 for the nine months ended September 30, 2013 and 2012, respectively.

Full Cost Method

'

Full Cost Method

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 three and nine months ended September 30, 2013 and 2012, respectively.

Three Months Ended

Nine Months Ended

September 30,

September 30,

2013

2012

2013

2012

Capitalized Certain Payroll and Other Internal Costs

$

894,573

$

79,471

$

2,257,022

$

7,366,101

Capitalized Interest Costs

1,597,129

1,811,088

4,525,906

4,426,429

Total

$

2,491,702

$

1,890,559

$

6,782,928

$

11,792,530

As of September 30, 2013, 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. There were no property sales in the nine months ended September 30, 2013 and 2012.

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 based on the estimated gross proved reserves as determined by independent petroleum engineers. 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 three months ended September 30, 2013 and 2012, the Company transferred into the full cost pool costs related to expired leases of $3.3 million and $0.5 million, respectively. For the nine months ended September 30, 2013 and 2012, the Company transferred into the full cost pool costs related to expired leases of $11.3 million and $3.1 million, respectively.

Capitalized costs of crude oil and natural gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved crude oil and natural gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the 12-month average price of crude oil and natural gas to estimated future production of proved crude oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense. As of September 30, 2013 and December 31, 2012, the Company has not realized any impairment of its properties.

Asset Retirement Obligations

'

Asset Retirement Obligations

Asset retirement obligation is included in other noncurrent liabilities and relates to future costs associated with the plugging and abandonment of crude oil and natural gas wells, removal of equipment and facilities from leased acreage and returning the land to its original condition. Estimates are based on estimated remaining lives of those wells based on reserve estimates, external estimates to plug and abandon the wells in the future, inflation, credit adjusted discount rates and federal and state regulatory requirements. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.

Debt Issuance Costs

'

Debt Issuance Costs

At September 30, 2013, the Company had capitalized debt issuance costs of $5.9 million in connection with the revolving credit facility and $14.3 million in connection with the "8% Senior Notes Due 2020" (see Note 4). 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.

The amortization of debt issuance costs for the three months ended September 30, 2013 and 2012 was $706,602 and $492,745, respectively. The amortization of debt issuance costs for the nine months ended September 30, 2013 and 2012 was $1,867,482 and $1,025,009, respectively.

Bond Premium on Senior Notes

'

Bond Premium on Senior Notes

At September 30, 2013, the Company had 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 for the three months ended September 30, 2013 and 2012 was $371,681 and $0, respectively. The amortization of the bond premium for the nine months ended September 30, 2013 and 2012 was $588,496 and $0, 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 September 30, 2013 and December 31, 2012, 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. Trade receivables are generally not collateralized.

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 customers 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.

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. 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.

Income Taxes

'

Income Taxes

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. 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. No valuation allowance has been recorded as of September 30, 2013 and December 31, 2012.

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.

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2013 and 2012 are as follows:

Three Months Ended

Nine Months Ended

September 30,

September 30,

2013

2012

2013

2012

Weighted average common shares outstanding – basic

62,426,341

62,589,256

62,750,952

62,410,110

Plus: Potentially dilutive common shares

Stock options and restricted stock

332,037

293,417

391,286

343,131

Weighted average common shares outstanding – diluted

62,758,378

62,882,673

63,142,238

62,753,241

Restricted stock excluded from EPS due to the anti-dilutive effect

2,290

34,702

9,295

23,099

As of September 30, 2013 and 2012, potentially dilutive shares from stock options were 251,963.

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.

On November 1, 2009, due to the volatility of price differentials in the Williston Basin, the Company de-designated all derivatives that were previously classified as cash flow hedges and in addition, the Company has elected not to designate any subsequent derivative contracts as accounting hedges. As such, all derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses are recorded to gain (loss) on settled derivatives and unrealized gains or losses are recorded to gain (loss) on mark-to-market of derivative instruments on the statements of comprehensive income rather than as a component of accumulated other comprehensive income (loss) or other income (expense). See Note 12 for a description of the derivative contracts which the Company has entered into.

Prior to November 1, 2009, the Company, at the inception of a derivative contract, designated the derivative as a cash flow hedge. For all derivatives designated as cash flow hedges, the Company formally documented the relationship between the derivative contract and the hedged items, as well as the risk management objective for entering into the derivative contract. To be designated as a cash flow hedge transaction, the relationship between the derivative and the hedged items must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis. The Company historically measured hedge effectiveness on a quarterly basis and hedge accounting would be discontinued prospectively if it determined that the derivative was no longer effective in offsetting changes in the cash flows of the hedged item. Gains and losses deferred in accumulated other comprehensive income (loss) related to cash flow hedge derivatives that become ineffective remain unchanged until the related production was delivered. If the Company determined that it was probable that a hedged forecasted transaction would not occur, deferred gains or losses on the derivative were recognized in earnings immediately.

Derivatives, historically, were recorded on the balance sheet at fair value and changes in the fair value of derivatives were recorded each period in current earnings or other comprehensive income (loss), depending on whether a derivative was designated as part of a hedge transaction and, if it was, depending on the type of hedge transaction. The Company's derivatives historically consisted primarily of cash flow hedge transactions in which the Company was hedging the variability of cash flows related to a forecasted transaction. Period to period changes in the fair value of derivative instruments designated as cash flow hedges were reported in accumulated other comprehensive income (loss) and reclassified to earnings in the periods in which the hedged item impacts earnings. The ineffective portion of the cash flow hedges were reflected in current period earnings as gain or loss from derivatives. Gains and losses on derivative instruments that did not qualify for hedge accounting were included in income or loss from derivatives in the period in which they occur. The resulting cash flows from derivatives were reported as cash flows from operating activities.

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 (which the Company uses) are excluded from this requirement but continue to be subject to the full cost method's impairment rules. There was no impairment recorded for the three months and nine months ended September 30, 2013 and 2012.

New Accounting Pronouncements

'

New Accounting Pronouncements

From time to time, new accounting pronouncements are issued by 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.

SIGNIFICANT_ACCOUNTING_POLICIE2

SIGNIFICANT ACCOUNTING POLICIES (Tables)	9 Months Ended
	Sep. 30, 2013
SIGNIFICANT 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 three and nine months ended September 30, 2013 and 2012, respectively.
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
	Capitalized Certain Payroll and Other Internal Costs		$	894,573		$	79,471		$	2,257,022		$	7,366,101
	Capitalized Interest Costs			1,597,129			1,811,088			4,525,906			4,426,429
	Total		$	2,491,702		$	1,890,559		$	6,782,928		$	11,792,530
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 three and nine months ended September 30, 2013 and 2012 are as follows:
			Three Months Ended						Nine Months Ended
			September 30,						September 30,
			2013			2012			2013			2012
	Weighted average common shares outstanding – basic			62,426,341			62,589,256			62,750,952			62,410,110
	Plus: Potentially dilutive common shares
	Stock options and restricted stock			332,037			293,417			391,286			343,131
	Weighted average common shares outstanding – diluted			62,758,378			62,882,673			63,142,238			62,753,241
	Restricted stock excluded from EPS due to the anti-dilutive effect			2,290			34,702			9,295			23,099

COMMON_AND_PREFERRED_STOCK_Tab

COMMON AND PREFERRED STOCK (Tables)	9 Months Ended
	Sep. 30, 2013
COMMON AND PREFERRED STOCK [Abstract]	'
Schedule of changes in the number of common stock shares	'
	The following is a schedule of changes in the number of common stock during the nine months ended September 30, 2013 and the year ended December 31, 2012:
		Nine Months Ended			Year Ended
		30-Sep-13			31-Dec-12
	Beginning Balance		63,532,622			63,330,421
	Stock Based Compensation		43,029			-
	Stock Options Exercised		-			10,500
	Restricted Stock Grants (Note 6)		299,401			890,379
	Stock Repurchased		(2,036,383	)		-
	Other Surrenders		(41,994	)		(698,678	)
	Ending balance		61,796,675			63,532,622

STOCK_OPTIONSSTOCKBASED_COMPEN1

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS (Tables)	9 Months Ended
	Sep. 30, 2013
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS [Abstract]	'
Restricted stock activity	'
	The following table reflects the outstanding restricted stock awards and activity related thereto for the nine months ended September 30, 2013:
		Nine Months Ended
		30-Sep-13
		Number of			Weighted-Average
		Shares			Price
	Restricted Stock Awards:
	Restricted Shares Outstanding at the Beginning of Period		777,437			$	18.93
	Shares Granted		299,401				15.38
	Shares Forfeited		(37,697	)			16.85
	Lapse of Restrictions		(361,103	)			19.15
	Restricted Shares Outstanding at September 30, 2013		678,038			$	17.37

INCOME_TAXES_Tables

INCOME TAXES (Tables)	9 Months Ended
	Sep. 30, 2013
INCOME TAXES [Abstract]	'
Income tax expense provision	'
	The income tax provision for the three and nine months ended September 30, 2013 and 2012 consists of the following:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
	Current Income Taxes	$	-	$	3,422	$	4,614	$	8,772
	Deferred Income Taxes
	Federal		956,000		175,000		19,925,000		30,660,000
	State		72,000		35,000		1,333,000		4,210,000
	Total Provision	$	1,028,000	$	213,422	$	21,262,614	$	34,878,772

FAIR_VALUE_Tables

FAIR VALUE (Tables)	9 Months Ended
	Sep. 30, 2013
FAIR VALUE [Abstract]	'
Financial instruments measured at fair value on recurring basis	'
	The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the balance sheet as of September 30, 2013 and December 31, 2012.
		Fair Value Measurements at
		September 30, 2013 Using
		Quoted Prices In Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
		(Level 1)		(Level 2)			(Level 3)
	Commodity Derivatives – Current Asset (crude oil swaps and collars)	$	-	$	22,692		$	-
	Commodity Derivatives – Current Liability (crude oil swaps and collars)		-		(21,841,508	)		-
	Commodity Derivatives – Non- Current Asset (crude oil swaps and collars)		-		934,545			-
	Commodity Derivatives – Non- Current Liability (crude oil swaps and collars)		-		(3,059,416	)		-
	Total	$	-	$	(23,943,687	)	$	-
		Fair Value Measurements at
		December 31, 2012 Using
		Quoted Prices In Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
		(Level 1)		(Level 2)			(Level 3)
	Commodity Derivatives – Current Asset (crude oil swaps and collars)	$	-	$	4,095,197		$	-
	Commodity Derivatives – Non-Current Asset (crude oil swaps and collars)		-		1,763,008			-
	Commodity Derivatives – Non-Current Liability (crude oil swaps and collars)		-		(2,547,745	)		-
	Total	$	-	$	3,310,460		$	-

DERIVATIVE_INSTRUMENTS_AND_PRI1

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Tables)	9 Months Ended
	Sep. 30, 2013
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT [Abstract]	'
Open Commodity Swap Contracts	'
	The following table reflects open commodity swap contracts as of September 30, 2013, the associated volumes and the corresponding fixed price.
	Settlement Period		Oil (Barrels)				Fixed Price
	Swaps-Crude Oil
	10/01/13 – 12/31/14			300,000			$	91.65
	10/01/13 – 12/31/13			120,000				89.5
	10/01/13 – 12/31/13			60,000				91.1
	10/01/13 – 12/31/13			30,000				94.5
	10/01/13 – 12/31/13			30,000				102.3
	10/01/13 – 12/31/13			30,000				94.5
	10/01/13 – 12/31/14			356,250				88.55
	10/01/13 – 12/31/14			356,250				88.6
	10/01/13 – 12/31/14			356,250				88.4
	10/01/13 – 12/31/14			356,250				88.5
	10/01/13 – 06/30/15			510,000				89.15
	10/01/13 – 12/31/15			810,000				89
	01/01/14 – 06/30/14			300,000				89.5
	01/01/14 – 06/30/14			240,000				90
	01/01/14 – 06/30/14			240,000				100
	01/01/14 – 12/31/14			120,000				91.35
	01/01/14 – 12/31/14			120,000				90
	01/01/14 – 12/31/14			240,000				90.15
	01/01/14 – 12/31/14			240,000				91
	01/01/14 – 12/31/14			120,000				93
	07/01/14 – 12/31/14			120,000				90
	07/01/14 – 12/31/14			120,000				90
	07/01/14 – 12/31/14			120,000				93.5
	07/01/14 – 12/31/14			30,000				90.58
	01/01/15 – 06/30/15			60,000				90.5
	01/01/15 – 06/30/15			180,000				88.55
	01/01/15 – 06/30/15			180,000				88
	01/01/15 – 06/30/15			60,000				90.75
	01/01/15 – 06/30/15			60,000				90.25
	01/01/15 – 12/31/15			360,000				89
	01/01/15 – 12/31/15			360,000				89.02
	01/01/15 – 12/31/15			180,000				89
	01/01/15 – 12/31/15			180,000				89
Open costless collar futures agreements	'
	The following table reflects open costless collar agreements as of September 30, 2013.
	Term		Oil (Barrels)				Floor/Ceiling Price			Basis
	Costless Collars – Crude Oil
	10/01/13 – 12/31/13			32,187			$	90.00/$103.50		NYMEX
	10/01/13 – 12/31/13			28,481			$	90.00/$106.50		NYMEX
	10/01/13 – 12/31/13			49,412			$	90.00/$110.00		NYMEX
	10/01/13 – 12/31/13			39,737			$	95.00/$107.00		NYMEX
	10/01/13 – 12/31/13			120,000			$	95.00/$110.70		NYMEX
	10/01/13 – 12/31/13			170,047			$	85.00/$98.00		NYMEX
	10/01/13 – 12/31/13			30,000			$	90.25/$97.95		NYMEX
	10/01/13 – 12/31/13			48,000			$	95.00/$106.90		NYMEX
	10/01/13 – 12/31/13			15,000			$	93.00/$100.00		NYMEX
	01/01/14 – 12/31/14			240,000			$	90.00/$99.05		NYMEX
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 September 30, 2013 and December 31, 2012, 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:
	Type of Contract	Balance Sheet Location		30-Sep-13				31-Dec-12
				Estimated Fair Value				Estimated Fair Value
	Derivative Assets:
	Swap Contracts	Current Assets/Liabilities		$	619,662			$	680,647
	Swap Contracts	Non-Current Assets			1,863,580				1,977,722
	Costless Collars	Current Assets/Liabilities			60,860				11,769,415
	Costless Collars	Non-Current Assets/Liabilities			120,398				5,629,996
	Total Derivative Assets			$	2,664,500			$	20,057,780
	Derivative Liabilities:
	Swap Contracts	Current Assets/Liabilities		$	(21,336,245	)		$	(2,037,070	)
	Swap Contracts	Non-Current Assets/Liabilities			(4,108,849	)			(3,170,945	)
	Costless Collars	Current Assets/Liabilities			(1,163,093	)			(6,317,795	)
	Costless Collars	Non-Current Liabilities			-				(5,221,510	)
	Total Derivative Liabilities			$	(26,608,187	)		$	(16,747,320	)
Gain (Loss) in Statement of Income	'
	The following disclosures are applicable to the Company's financial statements, as of September 30, 2013 and 2012, respectively:
				Amount of Loss Reclassified from
				AOCI into Income
				Three Months Ended								Nine Months Ended
				September 30,								September 30,
	Derivative Type	Location of Loss		2013				2012				2013		2012
		for Effective and
		Ineffective
		Portion of Derivative
		In Income
	Commodity - Cash Flow	Loss on Settled Derivatives		$	-			$	-			$	-	$	101,309
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 September 30, 2013
		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
	Offsetting of Derivative Assets:
	Current Assets		$	680,522			$	(657,830	)		$	22,692
	Non-Current Assets			1,983,978				(1,049,433	)			934,545
	Total Derivative Assets		$	2,664,500			$	(1,707,263	)		$	957,237
	Offsetting of Derivative Liabilities:
	Current Liabilities		$	(22,499,338	)		$	657,830			$	(21,841,508	)
	Non-Current Liabilities			(4,108,849	)			1,049,433				(3,059,416	)
	Total Derivative Liabilities		$	(26,608,187	)		$	1,707,263			$	(24,900,924	)
		Estimated Fair Value at December 31, 2012
		Gross Amounts of Recognized Assets				Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
	Offsetting of Derivative Assets:
	Current Assets		$	12,450,062			$	(8,354,865	)		$	4,095,197
	Non-Current Assets			7,607,719				(5,844,711	)			1,763,008
	Total Derivative Assets		$	20,057,781			$	(14,199,576	)		$	5,858,205
	Offsetting of Derivative Liabilities:
	Current Liabilities		$	(8,354,865	)		$	8,354,865			$	-
	Non-Current Liabilities			(8,392,456	)			5,844,711				(2,547,745	)
	Total Derivative Liabilities		$	(16,747,321	)		$	14,199,576			$	(2,547,745	)

ORGANIZATION_AND_NATURE_OF_BUS1

ORGANIZATION AND NATURE OF BUSINESS (Details)	9 Months Ended
	Sep. 30, 2013
	acre
ORGANIZATION AND NATURE OF BUSINESS [Abstract]	'
Percentage of mineral rights developed (in hundredths)	55.00%
Gas and oil acreage net mineral rights (in acres)	186,947

SIGNIFICANT_ACCOUNTING_POLICIE3

SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Cash and Cash Equivalents [Abstract]	'	'	'	'	'
Threshold amount of FDIC coverage	$250,000	'	$250,000	'	'
Accounts Receivable [Abstract]	'	'	'	'	'
Provision for doubtful accounts	'	'	925,000	'	0
Advance to Operators [Abstract]	'	'	'	'	'
Period for advance payments to be applied against joint interest billings	'	'	'90 days	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'	'
Depreciation expense	61,845	104,830	248,626	304,226	'
Full Cost Method [Abstract]	'	'	'	'	'
Capitalized Certain Payroll and Other Internal Costs	894,573	79,471	2,257,022	7,366,101	'
Capitalized Interest Cost	1,597,129	1,811,088	4,525,906	4,426,429	'
Total	2,491,702	1,890,559	6,782,928	11,792,530	'
Minimum percentage of proved reserves sold to be considered a significant alteration (in hundredths)	'	'	25.00%	'	'
Proceeds from sale of oil and gas properties	'	'	0	0	'
Capitalized costs related to expired leases subject to depletion	3,300,000	500,000	11,300,000	3,100,000	'
Discount rate (in hundredths)	'	'	10.00%	'	'
Debt Issuance Costs [Abstract]	'	'	'	'	'
Rate of Senior notes (in hundredths)	8.00%	'	8.00%	'	'
Amortization of debt issuance costs	706,602	492,745	1,867,482	1,025,009	'
Amortization of bond premium	371,681	0	588,496	0	'
Income Taxes [Abstract]	'	'	'	'	'
Valuation allowance	0	'	0	'	0
Net Income Per Common Share [Abstract]	'	'	'	'	'
Weighted average number of common shares outstanding-basic (in shares)	62,426,341	62,589,256	62,750,952	62,410,110	'
Stock options and restricted stock (in shares)	332,037	293,417	391,286	343,131	'
Weighted average number of common shares outstanding-diluted (in shares)	62,758,378	62,882,673	63,142,238	62,753,241	'
Restricted stock excluded from EPS due to the anti-dilutive effect (in shares)	2,290	34,702	9,295	23,099	'
Impairment [Abstract]	'	'	'	'	'
Asset Impairment Charges	'	'	0	'	0
Stock Options [Member]	'	'	'	'	'
Net Income Per Common Share [Abstract]	'	'	'	'	'
Stock options and restricted stock (in shares)	'	'	251,963	251,963	'
Revolving Credit Facility [Member]	'	'	'	'	'
Debt Issuance Costs [Abstract]	'	'	'	'	'
Capitalized costs in connection with debt	5,900,000	'	5,900,000	'	'
Senior Unsecured Notes [Member]	'	'	'	'	'
Debt Issuance Costs [Abstract]	'	'	'	'	'
Capitalized costs in connection with debt	14,300,000	'	14,300,000	'	'
Rate of Senior notes (in hundredths)	8.00%	'	8.00%	'	'
Bond Premium on Senior Notes [Member]	'	'	'	'	'
Debt Issuance Costs [Abstract]	'	'	'	'	'
Capitalized costs in connection with debt	$10,500,000	'	$10,500,000	'	'
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	'	'

CRUDE_OIL_AND_NATURAL_GAS_PROP1

CRUDE OIL AND NATURAL GAS PROPERTIES (Details) (USD $)	9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
	acre	acre	acre
	Project
	PlannedWells
Acquisitions [Abstract]	'	'	'
Capital expenditures incurred but not yet paid	$136,400,000	'	$91,800,000
Mineral acres acquired, net (in acres)	17,854	21,153	'
Average acquisition cost per net acre	1,234	1,913	'
Productive oil and gas wells, Number of wells, Gross	56	'	'
Productive oil and gas wells, Number of wells, Net	5.5	'	'
Productive Oil and Gas Wells, Cost	7,300,000	'	'
Unproved Properties [Abstract]	'	'	'
Unproven leasehold interests (in net acres)	64,500	'	64,500
Anticipated future period over which excluded costs will become subject to depletion	'5 years	'	'
Capitalized costs as of the balance sheet date that have been excluded	$85,100,000	'	$82,900,000
Number of defined drilling projects participating with Slawson	3	'	'
Slawson Projects [Member]	'	'	'
Unproved Properties [Abstract]	'	'	'
Percentage of participation interests, minimum (in hundredths)	4.50%	'	'
Percentage of participation interests, maximum (in hundredths)	50.00%	'	'
Aggregate acres of leasehold interest held	19,600	'	'
Windsor Project Area [Member]	'	'	'
Unproved Properties [Abstract]	'	'	'
Percentage of participation interests (in hundredths)	4.50%	'	'
Aggregate acres of leasehold interest held	2,100	'	'
South West Big Sky Project [Member]	'	'	'
Unproved Properties [Abstract]	'	'	'
Percentage of participation interests (in hundredths)	20.00%	'	'
Aggregate acres of leasehold interest held	5,500	'	'
Lambert Project [Member]	'	'	'
Unproved Properties [Abstract]	'	'	'
Percentage of participation interests (in hundredths)	50.00%	'	'
Aggregate acres of leasehold interest held	12,000	'	'

REVOLVING_CREDIT_FACILITY_AND_1

REVOLVING CREDIT FACILITY AND LONG TERM DEBT (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Line of Credit Facility [Line Items]	'
Rate of Senior unsecured notes (in hundredths)	8.00%
Revolving Credit Facility [Member]	'
Line of Credit Facility [Line Items]	'
Revolving credit facility, maximum borrowing	$750
Borrowing base	450
Borrowings under Credit Facility	45
Remaining borrowing capacity of Credit Facility	405
Permitted additional indebtedness	500
Percent of total additional permitted borrowing (in hundredths)	25.00%
Revolving credit facility, maturity date	30-Sep-18
Credit Facility interest rate description	'Borrowings under the Revolving Credit Facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.5% to 1.5% or LIBOR borrowings at the Adjusted LIBOR Rate (as defined) plus a spread ranging from 1.5% to 2.5%.B B The applicable spread is dependent upon amount of borrowings relative to the borrowing base.B B 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.B B A commitment fee is paid on the undrawn balance based on an annual rate of either 0.375% or 0.50%.B B At March 31, 2013, the commitment fee was 0.375% and the interest rate margin was 1.5% on LIBOR loans and 0.5% on base rate loans.
Commitment fee, description	'A commitment fee is paid on the undrawn balance based on an annual rate of either 0.375% or 0.50%.
Credit facility covenants	'The Revolving Credit Facility contains negative covenants that limit the Companybs 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, or make investments. 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. The Company was in compliance with its covenants under the Revolving Credit Facility at September 30, 2013.
Line Of Credit Facility Covenant Terms Current Ratio	1
Minimum [Member] | Revolving Credit Facility [Member]	'
Line of Credit Facility [Line Items]	'
Commitment fee percentage (in hundredths)	0.38%
Maximum [Member] | Revolving Credit Facility [Member]	'
Line of Credit Facility [Line Items]	'
Commitment fee percentage (in hundredths)	0.50%
8% Senior Notes Due 2020 [Member]	'
Line of Credit Facility [Line Items]	'
Principal amount of Senior unsecured notes	300
Rate of Senior unsecured notes (in hundredths)	8.00%
Maturity date	1-Jun-20
Price of Senior unsecured notes (in hundredths)	105.25%
Additional amount of Senior unsecured notes	200
Net proceeds from issuance of Senior unsecured notes	291.2
Additional net proceeds from issuance of Senior unsecured notes	200.1
Percentage of notes that can be redeemed (in hundredths)	35.00%
Rate of redemption price of notes (in hundredths)	108.00%
Limitation (in number of days) to redeemed the notes	'180 days
Limitation (in percentage of aggregate principal amount of Notes) to redeemed the notes	65.00%
Percentage of notes at redemption prices for prior to June 1, 2016 (in hundredths)	100.00%
Percentage of notes at redemption prices for the twelve-month period beginning on June 1, 2016 (in hundredths)	104.00%
Percentage of notes at redemption prices for the twelve-month period beginning on June 1, 2017 (in hundredths)	102.00%
Percentage of notes at redemption prices for beginning on June 1, 2018 (in hundredths)	100.00%
Number of days in default payment of interest	'30 days
Payment of certain final judgments	$25
Number of days related to payment certain final judgments	'60 days
LIBOR Loans [Member] | Revolving Credit Facility [Member]	'
Line of Credit Facility [Line Items]	'
Commitment fee percentage (in hundredths)	0.38%
Interest rate margin in effect during period (in hundredths)	1.50%
LIBOR Loans [Member] | Minimum [Member] | Revolving Credit Facility [Member]	'
Line of Credit Facility [Line Items]	'
Interest rate margin in effect during period (in hundredths)	1.50%
LIBOR Loans [Member] | Maximum [Member] | Revolving Credit Facility [Member]	'
Line of Credit Facility [Line Items]	'
Interest rate margin in effect during period (in hundredths)	2.50%
Alternate Base Rate Loans [Member] | Revolving Credit Facility [Member]	'
Line of Credit Facility [Line Items]	'
Interest rate margin in effect during period (in hundredths)	0.50%
Alternate Base Rate Loans [Member] | Minimum [Member] | Revolving Credit Facility [Member]	'
Line of Credit Facility [Line Items]	'
Interest rate margin in effect during period (in hundredths)	0.50%
Alternate Base Rate Loans [Member] | Maximum [Member] | Revolving Credit Facility [Member]	'
Line of Credit Facility [Line Items]	'
Interest rate margin in effect during period (in hundredths)	1.50%

COMMON_AND_PREFERRED_STOCK_Det

COMMON AND PREFERRED STOCK (Details) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
	Class
COMMON AND PREFERRED STOCK [Abstract]	'	'
Total shares of preferred and common stock authorized for issuance (in shares)	100,000,000	'
Number of classes of shares	2	'
Common stock, shares authorized (in shares)	95,000,000	95,000,000
Common stock, par value (in dollars per share)	$0.00	$0.00
Preferred stock, shares authorized (in shares)	5,000,000	5,000,000
Preferred stock, par value (in dollars per share)	$0.00	$0.00
Changes in number of common stock shares [Roll forward]	'	'
Beginning Balance (in shares)	63,532,622	63,330,421
Stock Based Compensation (in shares)	43,029	0
Stock Options Exercised (in shares)	0	10,500
Restricted Stock Grants (Note 6) (in shares)	299,401	890,379
Stock Repurchased (in shares)	-2,036,383	0
Other Surrenders (in shares)	-41,994	-698,678
Ending balance (in shares)	61,796,675	63,532,622
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Stock Based Compensation (in shares)	43,029	0
Stock Activity [Abstract]	'	'
Common stock surrendered by certain employees to cover tax obligations (in shares)	4,297	'
Fair value of common stock surrendered by certain employees to cover tax obligations	$64,000	'
Common stock surrendered by certain employees related to termination of employment (in shares)	37,697	'
Stock Repurchase Program [Abstract]	'	'
Stock repurchase program, amount approved	150,000,000	'
Treasury stock, repurchased and retired	26.1	'
Chief Executive Officer [Member]	'	'
Changes in number of common stock shares [Roll forward]	'	'
Stock Based Compensation (in shares)	43,029	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Stock Based Compensation (in shares)	43,029	'
Fair value of common stock issued, share based compensation	$608,430	'

STOCK_OPTIONSSTOCKBASED_COMPEN2

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
2009 Equity Incentive Plan [Member]	'
Stock Option Awards [Abstract]	'
Shares granted (in shares)	0
2006 Incentive Stock Option Plan [Member]	'
Stock Option Awards [Abstract]	'
Shares granted (in shares)	0
2013 Equity Incentive Plan [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Additional shares were authorized for grant (in shares)	1,500,000
Restricted Stock Awards [Member]	'
Restricted Stock Awards [Abstract]	'
Unrecognized compensation expense	6,200,000
Percent of forfeiture rate assumed for restricted stock (in hundredths)	0.00%
Restricted Stock Awards Activity [Roll forward]	'
Restricted Shares Outstanding at the Beginning of the Year (in shares)	777,437
Shares Granted (in shares)	299,401
Shares Forfeited (in shares)	-37,697
Lapse of Restrictions (in shares)	-361,103
Restricted Shares Outstanding at the End of the Year (in shares)	678,038
Restricted Stock Awards, Additional Disclosures [Abstract]	'
Restricted Shares Outstanding, Weighted-Average Price at the Beginning of the Year (in dollars per share)	18.93
Shares Granted, Weighted-Average Price (in dollars per share)	15.38
Shares Forfeited, Weighted-Average Price (in dollars per share)	16.85
Lapse of Restrictions, Weighted-Average Price (in dollars per share)	19.15
Restricted Shares Outstanding, Weighted-Average Price at the End of the Year (in dollars per share)	17.37
Stock Option Awards [Member]	'
Stock Option Awards [Abstract]	'
Options remain outstanding but unexercised (in shares)	251,963
Currently Outstanding Options [Abstract]	'
Forfeited (in shares)	0
Options expired during period (in shares)	0
Exercisable (in shares)	251,963
Share-based compensation expense	0
Stock Option Awards [Member] | 2006 Incentive Stock Option Plan [Member]	'
Stock Option Awards [Abstract]	'
Shares granted (in shares)	560,000
Shares granted (in dollars per share)	5.18
Stock Option Awards [Member] | Directors [Member] | 2006 Incentive Stock Option Plan [Member]	'
Stock Option Awards [Abstract]	'
Shares granted (in shares)	500,000
Stock Option Awards [Member] | Employee [Member] | 2006 Incentive Stock Option Plan [Member]	'
Stock Option Awards [Abstract]	'
Shares granted (in shares)	60,000

RELATED_PARTY_TRANSACTIONS_Det

RELATED PARTY TRANSACTIONS (Details) (Gallatin [Member], USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Gallatin [Member]	'	'
Related Party Transaction [Line Items]	'	'
Percentage interest that one of the Company's former directors owned (in hundredths)	25.00%	'
Payments to related parties	$0	$500

COMMITMENTS_CONTINGENCIES_Deta

COMMITMENTS & CONTINGENCIES (Details) (USD $)	9 Months Ended	63 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013
COMMITMENTS & CONTINGENCIES [Abstract]	'	'
Estimated reversal of revenue	$0.20	$1.50

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
INCOME TAXES [Abstract]	'	'	'	'	'	'	'
Decrease in deferred state income tax expense	'	'	$500,000	'	'	'	'
Income tax provision [Abstract]	'	'	'	'	'	'	'
Current Income Taxes	0	3,422	4,614	8,772	'	'	'
Deferred Income Taxes [Abstract]	'	'	'	'	'	'	'
Federal	956,000	175,000	19,925,000	30,660,000	'	'	'
State	72,000	35,000	1,333,000	4,210,000	'	'	'
Total Provision (Benefit)	1,028,000	213,422	21,262,614	34,878,772	'	'	'
Minimum Amount Tax Benefits Likely Realized Upon Settlement Percentage (in hundredths)	0.5	'	0.5	'	'	'	'
Unrecognized tax benefits	0	'	0	'	'	'	'
Unrecognized tax benefits, income tax penalties and interest expense	0	0	0	0	'	'	'
Unrecognized tax benefits, interest and penalties accrued	$0	'	$0	'	$0	'	'
Open tax years	'	'	'	'	'2012	'2011	'2010

FAIR_VALUE_Details

FAIR VALUE (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Total	$2,664,500	$20,057,781
Total	-26,608,187	-16,747,321
Transfers between Level 1 and Level 2	0	'
Fair Value, Measurements, Recurring [Member] | Quoted Prices In Active Markets for Identical Assets (Level 1) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity Derivatives - Current Asset (crude oil swaps and collars)	0	0
Commodity Derivatives - Non-Current Asset (crude oil swaps and collars)	0	0
Commodity Derivatives - Current Liability (crude oil swaps and collars)	0	'
Commodity Derivatives - Non-Current Liability (crude oil swaps and collars)	'	0
Total	0	'
Total	'	0
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity Derivatives - Current Asset (crude oil swaps and collars)	22,692	4,095,197
Commodity Derivatives - Non-Current Asset (crude oil swaps and collars)	934,545	1,763,008
Commodity Derivatives - Current Liability (crude oil swaps and collars)	-21,841,508	'
Commodity Derivatives - Non-Current Liability (crude oil swaps and collars)	-3,059,416	-2,547,745
Total	-23,943,687	'
Total	'	3,310,460
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity Derivatives - Current Asset (crude oil swaps and collars)	0	0
Commodity Derivatives - Non-Current Asset (crude oil swaps and collars)	0	0
Commodity Derivatives - Current Liability (crude oil swaps and collars)	0	'
Commodity Derivatives - Non-Current Liability (crude oil swaps and collars)	0	0
Total	0	'
Total	'	$0

FAIR_VALUE_Part_2_Details

FAIR VALUE, Part 2 (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Rate of Senior unsecured notes (in hundredths)	8.00%	'
Carrying Amount [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Senior unsecured notes	$500	$300
Revolving credit facility	45	124
Estimated Fair Value [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Senior unsecured notes	501	310.5
Revolving credit facility	$45	$124

FINANCIAL_INSTRUMENTS_Details

FINANCIAL INSTRUMENTS (Details) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
FINANCIAL INSTRUMENTS [Abstract]	'	'
Provision for Doubtful Accounts	$925,000	$0

DERIVATIVE_INSTRUMENTS_AND_PRI2

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Total volumes of open contracts	6,900,000	'	6,900,000	'
Weighted average price on open contracts	89.95	'	89.95	'
Oil Swap 1 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	300,000	'
Fixed Price (in dollars per barrel)	91.65	'	91.65	'
Oil Swap 1 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 1 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 2 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	120,000	'
Fixed Price (in dollars per barrel)	89.5	'	89.5	'
Oil Swap 2 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 2 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Oil Swap 3 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	60,000	'
Fixed Price (in dollars per barrel)	91.1	'	91.1	'
Oil Swap 3 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 3 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Oil Swap 4 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	30,000	'
Fixed Price (in dollars per barrel)	94.5	'	94.5	'
Oil Swap 4 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 4 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Oil Swap 5 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	30,000	'
Fixed Price (in dollars per barrel)	102.3	'	102.3	'
Oil Swap 5 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 5 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Oil Swap 6 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	30,000	'
Fixed Price (in dollars per barrel)	94.5	'	94.5	'
Oil Swap 6 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 6 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Oil Swap 7 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	356,250	'
Fixed Price (in dollars per barrel)	88.55	'	88.55	'
Oil Swap 7 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 7 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 8 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	356,250	'
Fixed Price (in dollars per barrel)	88.6	'	88.6	'
Oil Swap 8 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 8 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 9 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	356,250	'
Fixed Price (in dollars per barrel)	88.4	'	88.4	'
Oil Swap 9 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 9 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 10 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	356,250	'
Fixed Price (in dollars per barrel)	88.5	'	88.5	'
Oil Swap 10 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 10 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 11 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	510,000	'
Fixed Price (in dollars per barrel)	89.15	'	89.15	'
Oil Swap 11 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 11 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	30-Jun-15	'
Oil Swap 12 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	810,000	'
Fixed Price (in dollars per barrel)	89	'	89	'
Oil Swap 12 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil Swap 12 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-15	'
Oil Swap 13 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	300,000	'
Fixed Price (in dollars per barrel)	89.5	'	89.5	'
Oil Swap 13 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-14	'
Oil Swap 13 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	30-Jun-14	'
Oil Swap 14 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	240,000	'
Fixed Price (in dollars per barrel)	90	'	90	'
Oil Swap 14 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-14	'
Oil Swap 14 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	30-Jun-14	'
Oil Swap 15 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	240,000	'
Fixed Price (in dollars per barrel)	100	'	100	'
Oil Swap 15 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-14	'
Oil Swap 15 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	30-Jun-14	'
Oil Swap 16 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	120,000	'
Fixed Price (in dollars per barrel)	91.35	'	91.35	'
Oil Swap 16 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-14	'
Oil Swap 16 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 17 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	120,000	'
Fixed Price (in dollars per barrel)	90	'	90	'
Oil Swap 17 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-14	'
Oil Swap 17 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 18 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	240,000	'
Fixed Price (in dollars per barrel)	90.15	'	90.15	'
Oil Swap 18 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-14	'
Oil Swap 18 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 19 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	240,000	'
Fixed Price (in dollars per barrel)	91	'	91	'
Oil Swap 19 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-14	'
Oil Swap 19 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 20 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	120,000	'
Fixed Price (in dollars per barrel)	93	'	93	'
Oil Swap 20 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-14	'
Oil Swap 20 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 21 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	120,000	'
Fixed Price (in dollars per barrel)	90	'	90	'
Oil Swap 21 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jul-14	'
Oil Swap 21 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 22 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	120,000	'
Fixed Price (in dollars per barrel)	90	'	90	'
Oil Swap 22 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jul-14	'
Oil Swap 22 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 23 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	120,000	'
Fixed Price (in dollars per barrel)	93.5	'	93.5	'
Oil Swap 23 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jul-14	'
Oil Swap 23 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 24 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	30,000	'
Fixed Price (in dollars per barrel)	90.58	'	90.58	'
Oil Swap 24 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jul-14	'
Oil Swap 24 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Oil Swap 25 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	60,000	'
Fixed Price (in dollars per barrel)	90.5	'	90.5	'
Oil Swap 25 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-15	'
Oil Swap 25 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	30-Jun-15	'
Oil Swap 26 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	180,000	'
Fixed Price (in dollars per barrel)	88.55	'	88.55	'
Oil Swap 26 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-15	'
Oil Swap 26 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	30-Jun-15	'
Oil Swap 27 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	180,000	'
Fixed Price (in dollars per barrel)	88	'	88	'
Oil Swap 27 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-15	'
Oil Swap 27 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	30-Jun-15	'
Oil Swap 29 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	60,000	'
Fixed Price (in dollars per barrel)	90.25	'	90.25	'
Oil Swap 29 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-15	'
Oil Swap 29 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	30-Jun-15	'
Oil Swap 28 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	60,000	'
Fixed Price (in dollars per barrel)	90.75	'	90.75	'
Oil Swap 28 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-15	'
Oil Swap 28 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	30-Jun-15	'
Oil Swap 30 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	360,000	'
Fixed Price (in dollars per barrel)	89	'	89	'
Oil Swap 30 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-15	'
Oil Swap 30 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-15	'
Oil Swap 31 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	360,000	'
Fixed Price (in dollars per barrel)	89.02	'	89.02	'
Oil Swap 31 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-15	'
Oil Swap 31 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-15	'
Oil Swap 32 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	180,000	'
Fixed Price (in dollars per barrel)	89	'	89	'
Oil Swap 32 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-15	'
Oil Swap 32 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-15	'
Oil Swap 33 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Oil (in barrels)	'	'	180,000	'
Fixed Price (in dollars per barrel)	89	'	89	'
Oil Swap 33 [Member] | Minimum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-15	'
Oil Swap 33 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-15	'
Collar 1 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil (in barrels)	'	'	32,187	'
Price minimum (in dollars per barrel)	$90	'	$90	'
Price maximum (in dollars per barrel)	$103.50	'	$103.50	'
Collar 1 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Collar 2 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil (in barrels)	'	'	28,481	'
Price minimum (in dollars per barrel)	$90	'	$90	'
Price maximum (in dollars per barrel)	$106.50	'	$106.50	'
Collar 2 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Collar 3 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil (in barrels)	'	'	49,412	'
Price minimum (in dollars per barrel)	$90	'	$90	'
Price maximum (in dollars per barrel)	$110	'	$110	'
Collar 3 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Collar 4 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil (in barrels)	'	'	39,737	'
Price minimum (in dollars per barrel)	$95	'	$95	'
Price maximum (in dollars per barrel)	$107	'	$107	'
Collar 4 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Collar 5 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil (in barrels)	'	'	120,000	'
Price minimum (in dollars per barrel)	$95	'	$95	'
Price maximum (in dollars per barrel)	$110.70	'	$110.70	'
Collar 5 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Collar 6 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil (in barrels)	'	'	170,047	'
Price minimum (in dollars per barrel)	$85	'	$85	'
Price maximum (in dollars per barrel)	$98	'	$98	'
Collar 6 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Collar 7 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil (in barrels)	'	'	30,000	'
Price minimum (in dollars per barrel)	$90.25	'	$90.25	'
Price maximum (in dollars per barrel)	$97.95	'	$97.95	'
Collar 7 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Collar 8 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil (in barrels)	'	'	48,000	'
Price minimum (in dollars per barrel)	$95	'	$95	'
Price maximum (in dollars per barrel)	$106.90	'	$106.90	'
Collar 8 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Collar 9 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Oct-13	'
Oil (in barrels)	'	'	15,000	'
Price minimum (in dollars per barrel)	$93	'	$93	'
Price maximum (in dollars per barrel)	$100	'	$100	'
Collar 9 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-13	'
Collar 10 [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	1-Jan-14	'
Oil (in barrels)	'	'	240,000	'
Price minimum (in dollars per barrel)	$90	'	$90	'
Price maximum (in dollars per barrel)	$99.05	'	$99.05	'
Collar 10 [Member] | Maximum [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Settlement Period	'	'	31-Dec-14	'
Not Designated as Hedging Instrument [Member]	'	'	'	'
Crude Oil Derivative Contracts Cash-flow Not Designated as Hedges [Abstract]	'	'	'	'
Realized gain (loss) on price risk derivatives not designated as hedges	($8,096,075)	$1,701,296	($8,966,175)	($4,729,186)
Unrealized gain (loss) on price risk derivatives not designated as hedges	($29,353,161)	($22,308,470)	($27,254,147)	$18,125,928

DERIVATIVE_INSTRUMENTS_AND_PRI3

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT, Part 2 (Details) (USD $)

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Current Assets/Liabilities [Member]

Current Assets/Liabilities [Member]

Non-Current Assets/Liabilities [Member]

Non-Current Assets/Liabilities [Member]

Swap Contracts [Member]

Swap Contracts [Member]

Swap Contracts [Member]

Swap Contracts [Member]

Costless Collars [Member]

Costless Collars [Member]

Costless Collars [Member]

Costless Collars [Member]

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

Current Assets/Liabilities [Member]

Current Assets/Liabilities [Member]

Non-Current Assets/Liabilities [Member]

Non-Current Assets/Liabilities [Member]

Current Assets/Liabilities [Member]

Current Assets/Liabilities [Member]

Non-Current Assets/Liabilities [Member]

Non-Current Assets/Liabilities [Member]

Derivative Assets [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Instruments

$22,692

$4,095,197

'

'

'

'

'

'

'

'

$619,662

$680,647

'

'

$60,860

$11,769,415

'

'

Derivative Assets, Noncurrent

934,545

1,763,008

'

'

'

'

'

'

'

'

'

'

1,863,580

1,977,722

'

'

120,398

5,629,996

Total Derivatives Assets

2,664,500

20,057,780

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Liabilities [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Liabilities, Current

21,841,508

0

'

'

'

'

'

'

'

'

-21,336,245

-2,037,070

'

'

-1,163,093

-6,317,795

'

'

Derivative Liabilities, Noncurrent

3,059,416

2,547,745

'

'

'

'

'

'

'

'

'

'

-4,108,849

-3,170,945

'

'

0

-5,221,510

Total Derivatives Liabilities

-26,608,187

-16,747,320

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss on Settled Derivatives reclassified to income

'

'

0

0

0

101,309

'

'

'

'

'

'

'

'

'

'

'

'

Reconciliation between gross assets and liabilities and amounts reflected on balance sheet [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Offsetting of Financial Assets and Derivative Assets, Gross Amounts of Recognized Assets

2,664,500

20,057,781

'

'

'

'

680,522

12,450,062

1,983,978

7,607,719

'

'

'

'

'

'

'

'

Offsetting of Financial Liabilities and Derivative Liabilities, Gross Amounts of Recognized Assets

-26,608,187

-16,747,321

'

'

'

'

-22,499,338

-8,354,865

-4,108,849

-8,392,456

'

'

'

'

'

'

'

'

Offsetting of Financial Assets and Derivative Assets, Gross Amounts Offset in the Balance Sheet

-1,707,263

-14,199,576

'

'

'

'

-657,830

-8,354,865

-1,049,433

-5,844,711

'

'

'

'

'

'

'

'

Offsetting of Financial Liabilities and Derivative Liabilities, Gross Amounts Offset in the Balance Sheet

1,707,263

14,199,576

'

'

'

'

657,830

8,354,865

1,049,433

5,844,711

'

'

'

'

'

'

'

'

Offsetting of Financial Assets and Derivative Assets, Net Amounts of Assets Presented in the Balance Sheet

957,237

5,858,205

'

'

'

'

22,692

4,095,197

934,545

1,763,008

'

'

'

'

'

'

'

'

Offsetting of Financial Liabilities and Derivative Liabilities, Net Amounts of Assets Presented in the Balance Sheet

($24,900,924)

($2,547,745)

'

'

'

'

($21,841,508)

$0

($3,059,416)

($2,547,745)

'

'

'

'

'

'

'

'