Samson Resources Corp - FORM 10-Q

Samson Resources Corp - FORM 10-Q - August 14, 2014

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2014

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period From to

Commission File No. 333-186686

SAMSON RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

45-3991227

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

identification No.)

Samson Plaza

Two West Second Street

Tulsa, OK 74103-3103

(Address and zip code of registrant’s principal executive offices)

(918) 591-1791

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of August 14, 2014, Samson Resources Corporation had 845,600,000 shares of common stock outstanding.

SAMSON RESOURCES CORPORATION

TABLE OF CONTENTS


		Page Number
Part I. FINANCIAL INFORMATION		3
Item 1. Financial Statements (Unaudited)		3
Condensed Consolidated Balance Sheets at June 30, 2014 and December 31, 2013		3
Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2014 and 2013		4
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013		5
Notes to Condensed Consolidated Financial Statements		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 3. Quantitative and Qualitative Disclosures about Market Risk		43
Item 4. Controls and Procedures		44
Part II. OTHER INFORMATION		45
Item 1. Legal Proceedings		45
Item 1A. Risk Factors		45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		45
Item 3. Defaults Upon Senior Securities		45
Item 4. Mine Safety Disclosures		45
Item 5. Other Information		45
Item 6. Exhibits		46
Signatures		47
Index to Exhibits		48
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of CEO Pursuant to Rule 13a-14(b)
Certification of CFO Pursuant to Rule 13a-14(b)

EXPLANATORY NOTE

On July 22, 2014, we commenced an exchange offer with respect to our 9.750% Senior Notes due 2020. The information contained in this report should be read in conjunction with the information contained in the prospectus relating to such exchange offer, dated as of and filed with the Securities and Exchange Commission pursuant to Rule 424(b) under the Securities Act of 1933, as amended, on July 22, 2014 (the “Prospectus”).

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included in this report, other than statements of historical fact, may constitute forward-looking statements, including, but not limited to, statements or information regarding our future growth, results of operations, operational and financial performance, business prospects and opportunities and future events. Words such as, but not limited to, “anticipate,” “continue,” “estimate,” “expect,” “may,” “might,” “will,” “project,” “should,” “believe,” “intend,” “continue,” “could,” “plan,” “predict,” “potential,” “goal,” “foresee” and negatives of these words and similar expressions are intended to identify forward-looking statements. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. These statements are based on, but not limited to, management’s assessment of such factors as the condition of our industry and the competitive environment. These assessments could prove inaccurate.

All forward-looking statements involve risks and uncertainties. The occurrence of the events described and the achievement of the expected results depend on many events and assumptions, some or all of which are not predictable or within our control. Although the forward-looking statements contained in this report reflect our current beliefs based upon information currently available to us and upon assumptions which we believe to be reasonable, actual results may differ materially from expected results.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil and natural gas. Factors that may cause actual results to differ from expected results include, but are not limited to: (i) fluctuations in oil and natural gas prices; (ii) the uncertainty inherent in estimating our reserves, future net revenues and PV-10; (iii) the timing and amount of future production of oil and natural gas; (iv) cash flow and changes in the availability and cost of capital; (v) environmental, drilling and other operating risks, including liability claims as a result of our oil and natural gas operations; (vi) proved and unproved drilling locations and future drilling plans; (vii) the effects of existing and future laws and governmental regulations, including environmental, hydraulic fracturing and climate change regulation; (viii) restrictions contained in our debt agreements; (ix) our ability to generate sufficient cash to service our indebtedness; and (x) any of the risk factors and other cautionary statements described under the heading “Risk Factors” in the Prospectus and Part II, Item 1A—“Risk Factors” of this report.

Readers are cautioned not to place undue reliance on forward-looking statements. Should one or more of the risks or uncertainties referenced above occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Further, new factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible to predict all such factors, or to the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Each forward-looking statement speaks only as of the date of this report, and, except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share and per share data)


	June 30, 2014			December 31, 2013
Assets
Current assets:
Cash and cash equivalents	$	13,310		$	727
Accounts receivable, net		217,564			174,989
Prepaid expenses and other		11,929			11,484
Deferred tax assets		40,378			33,152

Total current assets		283,181			220,352
Property, plant and equipment, net:
Oil and gas properties, full cost method:
Proved properties		2,961,002			2,823,171
Unproved properties not being amortized		3,670,066			3,915,068
Other property and equipment		295,680			302,693

Total property, plant and equipment, net		6,926,748			7,040,932
Derivative assets		38			7,381
Deferred charges		113,936			125,816
Other noncurrent assets		31,979			43,205

Total assets	$	7,355,882		$	7,437,686

Liabilities and Equity
Current liabilities:
Accounts payable	$	35,943		$	36,267
Oil and gas revenues held for distribution		122,566			117,296
Accrued and other current liabilities		324,349			341,234
Derivative liabilities		68,369			40,529

Total current liabilities		551,227			535,326
Long-term debt		3,750,000			3,554,000
Derivative liabilities		15,064			11,241
Deferred credits and other long-term liabilities		71,259			66,117
Deferred income tax liabilities		1,449,706			1,563,975
Cumulative preferred stock subject to mandatory redemption ($0.10 par value, 180,000 shares authorized, issued and outstanding, recorded at redemption value)		196,859			191,035
Puttable common stock ($0.01 par value, 200,000 and 650,000 shares issued and outstanding at June 30, 2014 and December 31, 2013, respectively)		1,000			3,250
Commitments and contingencies (Note 12)
Shareholders’ equity:
Common stock ($0.01 par value, 2,000,000,000 shares authorized, with 845,400,000 and 835,400,000 shares issued and outstanding at June 30, 2014 and December 31, 2013, respectively)		8,290			8,290
Additional paid-in capital		4,240,007			4,212,793
Accumulated deficit		(2,917,915	)		(2,709,070	)
Accumulated other comprehensive (loss) income		(9,615	)		729

Total shareholders’ equity		1,320,767			1,512,742

Total liabilities and shareholders’ equity	$	7,355,882		$	7,437,686

The accompanying notes are an integral part of these condensed consolidated financial statements.

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND

COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(In thousands)


	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013		Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Revenues:
Natural gas and natural gas liquids sales	$	182,117		$	174,541	$	378,248		$	324,523
Crude oil sales		116,937			129,428		229,064			242,356
Commodity derivatives, net		(38,256	)		71,967		(95,586	)		21,958

Total revenues		260,798			375,936		511,726			588,837

Operating expenses:
Lease operating		56,426			48,578		101,904			98,333
Production and ad valorem taxes		21,819			21,145		42,296			39,637
Depreciation, depletion, and amortization		126,982			126,803		245,129			254,705
Impairment of oil and gas properties		312,070			11,061		312,070			80,330
Asset retirement obligation accretion		1,207			1,164		2,405			2,325
Related party management fee		5,513			5,250		11,025			10,500
General and administrative		38,235			34,264		79,214			64,935

Total operating expenses		562,252			248,265		794,043			550,765

Operating income (loss)		(301,454	)		127,671		(282,317	)		38,072
Interest (expense) income, net		(21,443	)		8		(41,919	)		13
Other (expense) income, net		(71	)		1,397		(203	)		377

Income (loss) before income taxes		(322,968	)		129,076		(324,439	)		38,462
Income tax provision (benefit)		(115,146	)		46,032		(115,595	)		13,647

Net income (loss)	$	(207,822	)	$	83,044	$	(208,844	)	$	24,815

Other comprehensive income (loss):
Unrealized gain (loss) from cash flow hedges, net of tax of $(5,410), $10,509, $(9,427) and $(520), respectively		(9,728	)		18,896		(16,963	)		(934	)
Reclassification for settled cash flow hedges, net of tax of $2,914, $2,757, $3,682 and $1,078, respectively		5,238			4,958		6,619			1,938

Other comprehensive income (loss)		(4,490	)		23,854		(10,344	)		1,004

Total comprehensive income (loss)	$	(212,312	)	$	106,898	$	(219,188	)	$	25,819

The accompanying notes are an integral part of these condensed consolidated financial statements.

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Operating activities:
Net income (loss)	$	(208,844	)	$	24,815
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Commodity derivatives, net		95,586			(21,958	)
Cash settlements of derivative instruments, net		(72,670	)		4,021
Stock based compensation expense		23,628			11,084
Depreciation, depletion and amortization		245,129			254,705
Impairment of oil and gas properties		312,070			80,330
Asset retirement obligation accretion		2,405			2,325
Accretion of preferred stock not capitalized		1,434			—
Amortization of debt cost not capitalized		3,163			—
Provision (benefit) for deferred income taxes		(115,750	)		13,746
Other noncash items		257			3,005
Change in operating assets and liabilities:
Accounts receivable		(53,142	)		(11,995	)
Prepaid expenses and other		(445	)		(3,371	)
Other noncurrent assets		—			(21,215	)
Accounts payable		(324	)		630
Oil and gas revenues held for distribution		5,270			19,959
Accrued and other current liabilities		18,679			(21,467	)
Deferred credits and other long-term liabilities		3,956			(2,302	)

Net cash provided by operating activities		260,402			332,312

Investing activities:
Capital expenditures—oil and gas properties		(484,875	)		(509,545	)
Capital expenditures—other property and equipment		(9,275	)		(23,785	)
Proceeds from divestitures—oil and gas properties		53,418			107,422
Proceeds from divestitures—other property and equipment		70			2,021

Net cash used in investing activities		(440,662	)		(423,887	)

Financing activities:
Proceeds from revolver		264,000			215,000
Repayment of revolver		(68,000	)		(80,000	)
Debt issuance costs		(967	)		—
Repurchase of puttable common stock		(2,190	)		(950	)

Net cash provided by financing activities		192,843			134,050

Net change in cash		12,583			42,475
Cash and cash equivalents at beginning of period		727			3,039

Cash and cash equivalents at end of period	$	13,310		$	45,514

The accompanying notes are an integral part of these condensed consolidated financial statements.

SAMSON RESOURCES CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Organization and Nature of Operations and Summary of Significant Accounting Policies

Organization and Nature of Operations

We are an independent oil and gas company incorporated in the state of Delaware and headquartered in Tulsa, Oklahoma. We also have corporate offices located in Denver, Colorado and Houston, Texas as well as several field locations throughout our core operating areas. We engage in the exploration, development and production of oil and gas properties located onshore in the United States. We have operations and acreage positions in the Anadarko, Arkoma, Greater Green River, Powder River, San Juan, East Texas and Williston Basins.

Unless the context requires otherwise, in this report references to (i) “Samson,” “Company,” “we,” “our,” and “us” refer to Samson Resources Corporation and its subsidiaries and (ii) “natural gas” or “gas” include natural gas liquids, which we may refer to as “NGLs”.

Interim Financial Statements

The accompanying condensed consolidated financial statements are unaudited. The consolidated balance sheet at December 31, 2013 is derived from our audited consolidated financial statements. In the opinion of management, the accompanying condensed consolidated financial statements reflect all adjustments necessary to present fairly our financial position at June 30, 2014 and our results of operations and cash flows for the relevant interim periods ended June 30, 2014 and 2013. All adjustments are of a normal recurring nature. The results of interim periods are not necessarily indicative of annual results.

On July 22, 2014, we commenced the exchange offer with respect to our 9.75% Senior Notes due 2020 (the “Senior Notes”). Certain disclosures have been condensed or omitted from these condensed consolidated interim financial statements. Accordingly, these consolidated interim financial statements should be read in conjunction with the information contained in the prospectus relating to such exchange offer, dated as of and filed with the Securities and Exchange Commission (the “SEC”) pursuant to Rule 424(b) under the Securities Act of 1933, as amended (the “Securities Act”), on July 22, 2014 (the “Prospectus”).

Significant Accounting Policies

As of June 30, 2014, there were no changes in significant accounting policies from those described in the December 31, 2013 audited consolidated financial statements.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management, are significant include oil and natural gas reserves used to compute depletion expense and the full cost ceiling limitation, depletion expense relating to oil and gas properties, allocations of value from unproved properties to proved properties when proved reserves are established or wells are completed, asset retirement obligations, fair value measurements used to record derivatives, employee stock based compensation, impairments of unproved property, accruals for revenue, expenses and capital expenditures, assumptions used to account for loss contingencies, projected compliance with debt covenant requirements and income taxes. We base our estimates on historical experience and on assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be determined with certainty, and accordingly, these estimates may change as facts and circumstances change. Actual results may differ from the estimates used in the preparation of our consolidated financial statements.

Reclassifications

Certain amounts previously reported have been reclassified to conform to the current period presentation. These reclassifications were made in the condensed consolidated statements of cash flows. This reclassification did not impact consolidated net income (loss), shareholders’ equity or total cash flows.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09 “Revenue from Contracts with Customers.” ASU 2014-09 creates a comprehensive framework for the recognition of revenue. ASU 2014-09 requires an entity to (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 is effective beginning on January 1, 2017 for public entities. We are currently evaluating the potential impact of ASU 2014-09 on our condensed consolidated financial statements.

Note 2. Property, Plant and Equipment

Property, plant and equipment consisted of the following as of the dates presented (in thousands):


	June 30, 2014			December 31, 2013
Oil and gas properties:
Proved properties	$	8,747,950		$	8,075,440
Unproved properties excluded from amortization		3,578,095			3,789,432
Uncompleted capital project costs excluded from amortization		91,971			125,636
Accumulated depletion		(5,786,948	)		(5,252,269	)

Net oil and gas properties		6,631,068			6,738,239

Other property and equipment:		376,271			368,980
Accumulated depreciation		(80,591	)		(66,287	)

Net other property and equipment		295,680			302,693

Property, plant and equipment, net of accumulated depletion and depreciation	$	6,926,748		$	7,040,932

Oil and Gas Properties

We utilize the full cost method of accounting for oil and gas properties. During the three and six months ended June 30, 2014 and 2013, we transferred approximately $168.8 million and $4.7 million, respectively, and $231.6 million and $8.5 million, respectively, in unproved property value to proved property due to acreage expirations, planned divestitures of unproved properties and our assessment of the likelihood that certain acreage positions will be developed.

We capitalize internal costs that are directly related to the acquisition, exploration and development of oil and gas properties, which are included in proved properties and are subject to depletion. We also capitalize interest costs for properties with exploration and development activities, which are included in unproved oil and gas properties and are excluded from amortization. The following table summarizes capitalized internal costs and capitalized interest expense for the three and six months ended June 30, 2014 and 2013 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Capitalized internal costs, excluding stock compensation	$	7,955	$	8,811	$	15,878	$	16,043
Capitalized stock compensation		902		1,190		3,525		1,788
Capitalized interest costs		64,698		84,904		128,344		166,443

	$	73,555	$	94,905	$	147,747	$	184,274

During the three and six months ended June 30, 2014 and 2013, the net capitalized cost of oil and gas properties subject to depletion exceeded the ceiling amount during the quarterly full cost ceiling test. As a result, we recorded impairment expense associated with our oil and gas properties in the amount of $312.1 million and $11.1 million for the three months ended June 30, 2014 and 2013, respectively, and $312.1 million and $80.3 million for the six months ended June 30, 2014 and 2013, respectively. Our pre-tax impairment expense associated with our oil and gas properties for the six months ended June 30, 2014 and 2013 was increased (decreased) by $8.0 million and $(74.2) million, respectively, as a result of derivatives designated as cash flow hedges.

Note 3. Other Noncurrent Assets

The following table presents the components of other noncurrent assets as of the dates presented (in thousands):


	June 30, 2014		December 31, 2013
Tubular and oil and gas equipment	$	21,379	$	38,077
Prepaid drilling costs		4,741		1,400
Other		5,859		3,728

	$	31,979	$	43,205

Note 4. Accrued and Other Current Liabilities

The following table presents the components of accrued and other current liabilities as of the dates presented (in thousands):


	June 30, 2014		December 31, 2013
Accrued interest	$	92,205	$	90,811
Accrued expenditures		103,306		97,838
Accrued compensation and benefits		27,501		37,394
Production and ad valorem taxes		39,665		41,637
Book cash overdrafts		2,772		26,786
Asset retirement obligation (current portion)		10,862		11,617
Advance payments from and payables to partners		37,579		29,766
Other		10,459		5,385

	$	324,349	$	341,234

Note 5. Asset Retirement Obligations

Asset retirement obligations primarily relate to producing wells and represent the estimated discounted costs for future dismantlement and abandonment of oil and gas properties. The following table provides a reconciliation of the changes in the estimated asset retirement obligations for the periods presented (in thousands):


	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Asset retirement obligations as of beginning of period	$	60,408		$	55,228
Liabilities incurred		557			544
Liabilities settled		(2,246	)		(1,978	)
Disposition of wells		(1,776	)		(1,995	)
Accretion expense		2,405			2,325
Revisions		1,141			1,245

Asset retirement obligations as of end of period	$	60,489		$	55,369

Note 6. Derivative Financial Instruments

Objectives and Strategies

We are exposed to market risk from changes in energy commodity prices related to our crude oil, natural gas and NGL production activities. We utilize commodity-based derivative instruments to manage our exposure to changes in expected future cash flows from forecasted sales of oil, natural gas and NGLs attributable to commodity price risk. These derivatives include fixed price swap agreements, basis swaps and collars containing extension options.

Accounting Treatment

We designated a portion of our commodity derivatives as cash flow hedges of the forecasted sales of our oil and natural gas production. The table below summarizes the various methods in which we account for our derivative instruments and the impact on our consolidated financial statements:


	Recognition and Measurement
Accounting Treatment	Balance Sheet		Statement of Income (Loss)
Normal purchase/normal sale	Ÿ	Fair value not recorded	Ÿ	Change in fair value not recognized in earnings

Mark-to-market	Ÿ	Recorded at fair value	Ÿ	Change in fair value recognized in earnings

Cash flow hedge	Ÿ	Recorded at fair value	Ÿ	Ineffective portion of gain or loss on the derivative instrument is recognized in earnings
Cash flow hedge	Ÿ	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss)	Ÿ	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings

For cash flow hedges, we formally document all relationships between hedging instruments and hedged items as well as risk-management objectives. We specifically identify the forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships quarterly to determine whether the hedge relationships are highly effective on a retrospective and prospective basis. The agreements and contracts designated as cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness could be recognized as a result of locational differences between the hedging derivative and the hedged item.

Derivatives

Our natural gas derivatives settle against the last day prompt month New York Mercantile Exchange (“NYMEX”) Henry Hub futures price. Our natural gas basis swaps settle against the respective Inside FERC first of the month index. Our crude oil derivatives settle against the calendar month average of the prompt month NYMEX West Texas Intermediate futures price. NGL fixed price swap agreements settle against the respective Mont Belvieu or Conway Oil Price Information Service calendar month averages.

The following table sets forth our net open derivative positions as of June 30, 2014 for derivatives designated as cash flow hedging instruments:


	Natural Gas Fixed Price Swaps				Crude Oil Fixed Price Swaps
Period	Volume (MMBtu)		Weighted Average Price ($/MMBtu)		Volume (MBBls)		Average Price ($/BBl)
Remainder of 2014		36,208,600	$	4.14		460	$	92.23
2015		37,317,000	$	4.09		365	$	91.30
2016		31,535,800	$	4.08		—	$	—
2017		14,600,000	$	3.92		—	$	—

The following tables set forth our net open derivative positions as of June 30, 2014 for derivatives not designated as cash flow hedging instruments:


	Natural Gas Fixed Price Swaps				Crude Oil Fixed Price Swaps
Period	Volume (MMBtu)		Weighted Average Price ($/MMBtu)		Volume (MBBls)		Average Price ($/BBl)
Remainder of 2014		20,240,000	$	4.15		2,576	$	90.34
2015		900,000	$	4.77		913	$	90.76


	Natural Gas Collars
Period	Volume (MMBtu)		Weighted Average Floor/Ceiling Price ($/MMBtu)
2015		8,200,000	$	4.03/5.20
2016 (a)		—		—


	Ethane Fixed Price Swaps				Propane Fixed Price Swaps				Natural Gasoline Fixed Price Swaps				Butane Fixed Price Swaps
Period	Volume (Tgal)		Weighted Avg. Price ($/gal)		Volume (Tgal)		Weighted Avg. Price ($/gal)		Volume (Tgal)		Weighted Avg. Price ($/gal)		Volume (Tgal)		Weighted Avg. Price ($/gal)
Remainder of 2014		25,889	$	0.24		15,641	$	1.02		7,929	$	1.98		8,501	$	1.30
2015		5,136	$	0.27		3,104	$	1.09		1,571	$	2.03		1,686	$	1.29

(a)

We have entered into natural gas derivative contracts which give counterparties the option to extend certain option contracts currently in place for 2015 for an additional twelve-month period if elected on December 24, 2015. If extended, options covering a notional volume of 10,980,000 MMBtu will exist during 2016 with a floor price of $4.00/MMBtu and a ceiling price of $5.13/MMBtu.

Financial Statement Presentation

To the extent a legal right to offset exists, we net the value of our derivatives with the same counterparty in the accompanying consolidated balance sheets.

The following table presents the gross fair value of our derivative instruments as of the dates presented (in thousands):


	June 30, 2014
	Gross Assets		Gross Liabilities			Netting (a)			Net Amount Presented in Consolidated Balance Sheets
Derivatives designated as cash flow hedges:
Current derivative assets	$	748	$	—		$	(748	)	$	—
Noncurrent derivative assets		1,450		—			(1,450	)		—
Current derivative liabilities		—		(22,303	)		748			(21,555	)
Noncurrent derivative liabilities		—		(14,640	)		1,450			(13,190	)

Total derivatives designated as cash flow hedges		2,198		(36,943	)		—			(34,745	)

Derivatives not designated as cash flow hedges:
Current derivative assets		7,402		—			(7,402	)		—
Noncurrent derivative assets		2,538		—			(2,500	)		38
Current derivative liabilities		—		(54,216	)		7,402			(46,814	)
Noncurrent derivative liabilities		—		(4,374	)		2,500			(1,874	)

Total derivatives not designated as cash flow hedges		9,940		(58,590	)		—			(48,650	)

Total derivatives	$	12,138	$	(95,533	)	$	—		$	(83,395	)


	December 31, 2013
	Gross Assets		Gross Liabilities			Netting (a)			Net Amount Presented in Consolidated Balance Sheets
Derivatives designated as cash flow hedges:
Current derivative assets	$	788	$	—		$	(788	)	$	—
Noncurrent derivative assets		3,070		—			(533	)		2,537
Current derivative liabilities		—		(4,484	)		788			(3,696	)
Noncurrent derivative liabilities		—		(2,725	)		533			(2,192	)

Total derivatives designated as cash flow hedges		3,858		(7,209	)		—			(3,351	)

Derivatives not designated as cash flow hedges:
Current derivative assets		4,136		—			(4,136	)		—
Noncurrent derivative assets		11,662		—			(6,818	)		4,844
Current derivative liabilities		—		(40,969	)		4,136			(36,833	)
Noncurrent derivative liabilities		—		(15,867	)		6,818			(9,049	)

Total derivatives not designated as cash flow hedges		15,798		(56,836	)		—			(41,038	)

Total derivatives	$	19,656	$	(64,045	)	$	—		$	(44,389	)

(a)

Our derivative assets and liabilities are labeled accordingly in the condensed consolidated balance sheets and are presented on a net basis. We net derivative assets and liabilities when a legally enforceable master netting agreement exists between the counterparty to a derivative contract and us. All of our derivatives are entered into with banks that are part of our RBL Revolver (as defined below) or their respective affiliates. As a result, we do not have any margin requirements.

Cash Flow Hedges

We use derivative instruments to hedge the cash flows associated with the anticipated sales of our oil and natural gas production activities. Accumulated other comprehensive loss at June 30, 2014 included $9.6 million, net of tax, related to these cash flow hedges that will be recognized over the next four years as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $5.7 million in losses, net of income tax, over the next twelve months. For derivatives designated as cash flow hedges, the following table presents separately the pretax cash settlements and unrealized gains and losses included in the condensed consolidated statements of income (loss) and comprehensive income (loss) for the periods presented (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013			Classification
Net gain (loss) recognized in other comprehensive loss due to the derivative movement of the effective portion of cash flow hedges	$	(15,136	)	$	29,405		$	(26,390	)	$	(1,454	)	AOCI
Net gain (loss) reclassified from accumulated other comprehensive loss into income due to realized gains (losses) associated with sales of production	$	8,152		$	(7,715	)	$	10,301		$	(3,016	)	Commodity Derivatives, net
Net gain (loss) recognized in income due to the movement of the ineffective portion of cash flow hedges	$	—		$	842		$	—		$	786		Commodity Derivatives, net

For the three and six months ended June 30, 2014 and 2013, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below (in thousands). The reclassifications out of accumulated other comprehensive income (loss) are included in commodity derivatives, net in the condensed consolidated statements of income (loss) and comprehensive income (loss).


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Balance, beginning of period	$	(5,125	)	$	(16,536	)	$	729		$	6,314
Other comprehensive loss before reclassifications		(9,728	)		18,896			(16,963	)		(934	)
Cash settlements of cash flow hedges reclassified into earnings from accumulated other comprehensive income (loss)		5,238			4,958			6,619			1,938

Net current period other comprehensive loss		(4,490	)		23,854			(10,344	)		1,004

Balance, end of period	$	(9,615	)	$	7,318		$	(9,615	)	$	7,318

Note 7. Fair Value Measurements

The following table presents, by level within the fair value hierarchy, our commodity derivative assets and liabilities that are measured at fair value on a recurring basis as of the dates presented (in thousands):


	Gross			Fair Value Measurement Using:
	Carrying Amount			Level 1 Inputs		Level 2 Inputs			Level 3 Inputs
June 30, 2014 assets (liabilities):
Derivative assets	$	12,138		$	—	$	7,219		$	4,919
Derivative liabilities	$	(95,533	)	$	—	$	(86,281	)	$	(9,252	)
December 31, 2013 assets (liabilities):
Derivative assets	$	19,656		$	—	$	15,731		$	3,925
Derivative liabilities	$	(64,045	)	$	—	$	(53,539	)	$	(10,506	)

Management evaluates the methods and assumptions in a third party valuation report as part of our process in estimating the fair value of our derivatives. The following methods and assumptions were used to estimate the fair values in the table above:

Level 2 Fair Value Measurements

Derivatives—The fair value of oil and natural gas commodity swaps has been calculated utilizing quoted market prices that are observable.

Level 3 Fair Value Measurements

Derivatives—The fair value of NGL swaps has been calculated utilizing third party pricing services and discount factors. The fair value of natural gas collars has been calculated utilizing futures prices and market implied volatilities of the underlying futures contracts.

The following table presents a reconciliation of changes in the fair value of our financial assets and liabilities classified as Level 3 fair value measurements in the fair value hierarchy for the indicated periods (in thousands):


	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014			2013
Beginning balance	$	(4,709	)	$	603	$	(6,581	)	$	4,738
Total gains or losses:
Included in earnings		2,101			2,527		7,925			(2,952	)
Included in other comprehensive loss		—			1,743		—			1,904
Settlements		(1,725	)		1,793		(5,677	)		2,976

Ending balance	$	(4,333	)	$	6,666	$	(4,333	)	$	6,666


	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014			2013
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain (loss) of assets still held	$	(966	)	$	4,731	$	(1,706	)	$	5,174

Other Financial Instruments

Our cash and cash equivalents are comprised of bank and money market accounts. The carrying values of our cash and cash equivalents, accounts receivable and accounts payable approximate fair value, primarily due to the short-term nature of these instruments. At June 30, 2014 and December 31, 2013, the estimated fair value of our long-term debt, including current maturities, was approximately $3.9 billion and $3.8 billion, respectively. Our measurements are based primarily upon quoted trading prices for our Senior Notes and internal models, and therefore include both Level 2 and Level 3 measurements under the fair value hierarchy.

Note 8. Debt

Long-Term Debt

As of the dates presented, our long-term debt consisted of the following (in thousands):


	June 30, 2014		December 31, 2013
RBL Revolver	$	500,000	$	304,000
Second Lien Term Loan		1,000,000		1,000,000
9.75% Senior Notes		2,250,000		2,250,000

Total		3,750,000		3,554,000
Less: current portion		—		—

Total long-term debt	$	3,750,000	$	3,554,000

RBL Revolver

In May 2014, we amended the credit agreement governing the reserve-based revolving credit facility (the “RBL Revolver”) to, among other things, modify the financial performance covenant to provide that we shall maintain:

•

beginning with the first quarter of 2014 and terminating at the end of 2015, a ratio of consolidated total first lien debt to consolidated EBITDA (each as defined in the credit agreement, with consolidated EBITDA measured on a rolling four-quarter basis) of not more than 1.5 to 1.0 as of the end of each fiscal quarter; and

•

beginning with the first quarter of 2016, a ratio of consolidated total debt to consolidated EBITDA (each as defined in the credit agreement, with consolidated EBITDA measured on a rolling four-quarter basis) of not more than 4.5 to 1.0 as of the end of each fiscal quarter.

In addition, the amendment modified the credit agreement governing the RBL Revolver to (i) reduce the borrowing base from approximately $1.8 billion to $1.0 billion and (ii) permit us to incur an additional $500.0 million of second lien debt without a further, related reduction to the borrowing base, subject to certain limitations and conditions. Our borrowing base under the RBL Revolver is based upon our proved reserves and is redetermined semi-annually by our lenders. In addition, the borrowing base may be adjusted pursuant to certain non-scheduled redeterminations, including in connection with certain dispositions of our proved reserves. At June 30, 2014, we had outstanding borrowings of approximately $500.0 million and availability of approximately $498.2 million under the RBL Revolver after giving effect to outstanding letters of credit. During the six months ended June 30, 2014, the weighted average interest rate for borrowings under the RBL Revolver was 2.0%.

Senior Notes

In connection with the issuance of the Senior Notes, we entered into a registration rights agreement, which includes certain provisions requiring that we file a registration statement to exchange the Senior Notes for new registered notes to be declared effective within 450 days of the original issue date of the Senior Notes. In accordance with the terms of the registration rights agreement, if we have not exchanged the Senior Notes or if a shelf registration statement covering the resale of the Senior Notes has not been declared effective by the 450th day after the original issue date of the Senior Notes, additional interest shall accrue on the principal amount of the Senior Notes. We began incurring additional interest on the Senior Notes in May 2013. For the six months ended June 30, 2014, our weighted average effective interest rate incurred on our Senior Notes was 10.7%. On July 22, 2014, we commenced the exchange offer with respect to the Senior Notes, and we expect the exchange offer to be completed on or about August 19, 2014, subject to possible extensions by us. Upon the completion of the exchange offer of the Senior Notes, the additional interest will no longer accrue on the Senior Notes.

Debt Covenants

Under the RBL Revolver credit agreement, we are subject to the financial performance covenant described above. This covenant may restrict our ability to engage in certain actions, including by potentially limiting our ability to sell assets or make future borrowings under the RBL Revolver or incur other additional indebtedness. Forecasting our compliance with the financial performance covenant in future periods is inherently uncertain. Factors that could impact our future compliance with the financial performance covenant include future realized prices for sales of oil, natural gas and natural gas liquids, estimated future production, returns generated by our capital program, future interest costs, future operating costs, proceeds received from future asset sales and future equity contributions, among others.

The credit agreements governing the RBL Revolver and our second lien term loan credit facility (the “Second Lien Term Loan”) and the indenture governing the Senior Notes (collectively, the “Debt Agreements”) all contain additional customary non-financial covenants that, among other things, restrict our ability to pay dividends, restrict our ability to sell assets, restrict our ability to make acquisitions or investments, and restrict our ability to incur additional indebtedness. In addition, the Debt Agreements contain reporting and administrative requirements, including, but not limited to, providing financial statements, compliance certificates and other documents to our counterparties to the Debt Agreements under prescribed timelines.

Subject to any cure periods, the consequences of non-compliance with our debt covenants generally include, but are not limited to, the ability of our counterparties to the Debt Agreements to accelerate our obligation to repay amounts outstanding under our Debt Agreements.

Note 9. Puttable Common Stock

During the six months ended June 30, 2014, 450,000 shares of common stock were repurchased for approximately $2.2 million. For shares repurchased at an amount less than the original cost, the amount reflected outside of permanent equity is reclassified to common stock and additional paid in capital in the condensed consolidated balance sheets.

Note 10. Stock Compensation

2011 Stock Incentive Plan

On April 16, 2012, we implemented the Samson Resources Corporation 2011 Stock Incentive Plan (the “2011 Plan”). The 2011 Plan authorizes the grant of awards in the form of restricted shares, phantom stock, warrants or other securities that are convertible or exercisable into shares of common stock. Employees, members of the Board of Directors, consultants and service providers of Samson are eligible to receive awards under the 2011 Plan. In the second quarter of 2013, we amended the 2011 Plan to increase the total number of securities available to be granted from 10% of the common stock on a fully diluted basis to 98,200,000 securities.

Stock Options

The following table provides information about our stock option activity under the 2011 Plan for the six months ended June 30, 2014:


	Number of Stock Options			Range of Exercise Prices	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (years)
Outstanding at December 31, 2013		79,869,650		$4.00 - $7.50	$	5.29		9.0
Options granted		3,675,600		$2.50		2.50
Options forfeited		(4,518,630	)	$2.50 - $5.00		3.21
Options expired		(2,901,160	)	$2.50 - $5.00		3.32

Outstanding at June 30, 2014		76,125,460		$2.50 - $7.50	$	3.38		8.6

Vested during period		6,090,350		$2.50 - $7.50	$	4.53		8.9

Exercisable at June 30, 2014		21,084,030		$2.50 - $7.50	$	3.29		8.2

Stock options are valued at the date of award and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The compensation cost associated with stock options impacts our accumulated paid in capital. The following table summarizes information about stock based compensation related to stock options for the three and six months ended June 30, 2014 and 2013 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Grant date fair value for stock options granted during the period	$	1,065	$	59,089	$	3,470	$	59,089

Stock based compensation related to stock options:
Expensed during the period	$	8,285	$	5,667	$	19,379	$	10,629
Capitalized during the period		863		1,190		3,486		1,788

Total stock based compensation related to stock options during the period	$	9,148	$	6,857	$	22,865	$	12,417

Income tax benefit related to stock options	$	3,044	$	2,025	$	7,269	$	3,799

In calculating the compensation expense for stock options, we estimated the fair value of each grant using the Black-Scholes-Merton option pricing model. Assumptions utilized in the model are shown below:


	Awards issued in 2014	Awards issued in 2013
Risk-free interest rate	1.98 - 2.20%	1.35 - 2.25%
Expected term (years)	7.25	7.25
Expected volatility	49.70 - 49.86%	47.91 - 49.40%
Expected dividend yield	—	—

The risk-free interest rate is based on U.S. Treasury zero-coupon security issuances with remaining terms equal to the expected term. The expected term of the options is based on vesting schedules, consideration of contractual terms and expectations of future employee behaviors. Expected volatilities are based on a combination of historical and implied volatilities of comparable companies.

The forfeiture rate for non-officer employee stock options issued under the 2011 Plan is 9%. We assumed no future forfeitures of stock options issued to our executive team and 5% for other officers.

The following table reflects the future stock-based compensation cost to be recognized (either expensed or capitalized) for the nonvested stock option awards that were outstanding at June 30, 2014 (in thousands):


Remainder of 2014	$	16,217
2015		31,094
2016		16,855
2017		15,327
2018		4,741
2019		160

	$	84,394

Modifications to our outstanding stock options result in additional compensation cost if the fair value of the modified award immediately after the modification exceeds the fair value of the outstanding award immediately before the modification. For vested awards, the modification results in immediate expense recognition. For unvested awards, the additional compensation cost is recognized over the remaining requisite service period. During the first quarter of 2014, we modified the terms of certain stock options issued under the 2011 Plan. The exercise price for all non-officer employee held stock options was changed to $2.50 from the original $5.00 or $4.00 exercise prices established in the original award. In addition, modifications were made to certain stock options held by officers of the Company, which also included reductions in the number of stock options held by our Chief Executive Officer and decreases to the exercise prices of certain stock options held by all officers. After the modifications, the exercise prices for a majority of our outstanding stock options was $2.50 while a portion of our stock options held by our Chief Executive Officer had exercise prices of $4.00, $5.00, and $7.50. The stock option modifications will increase stock compensation expense in future periods. The modifications increased stock compensation expense by $9.0 million after the effects of capitalization for the six months ended June 30, 2014.

Restricted Stock

Grants of 10,000,000 shares of restricted stock were made to certain officers during the six months ended June 30, 2014. The shares of restricted stock were granted with a vesting schedule of 20% a year, with the first 20% vesting in April 2015.

The following table provides information about our restricted stock activity under the 2011 Plan for the six months ended June 30, 2014:


	Number of Shares
Outstanding at December 31, 2013		6,400,000
Stock granted		10,000,000
Stock forfeited		—

Shares outstanding at June 30, 2014		16,400,000

Vested during period		—

Restricted stock is valued at the date of award based on the estimated fair value of an unrestricted share reduced by a lack of marketability discount of 15%. Compensation cost is recognized on a straight-line basis over the requisite service period. We assume no future forfeitures of restricted stock issued to our executive team and 5% for other officers. The compensation cost associated with restricted stock impacts our accumulated paid in capital. The following table summarizes information about stock based compensation related to restricted stock for the three and six months ended June 30, 2014 and 2013 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Grant date fair value for restricted stock granted during the period	$	2,130	$	19,720	$	21,255	$	19,720

Stock based compensation related to restricted stock:
Expensed during the period	$	2,107	$	455	$	3,274	$	455
Capitalized during the period		39		—		39		—

Total stock based compensation related to restricted stock during the period	$	2,146	$	455	$	3,313	$	455

Income tax benefit related to restricted stock	$	701	$	163	$	1,041	$	163

The following table reflects the future stock based compensation cost to be recognized (either expensed or capitalized) for the shares of restricted stock as of June 30, 2014 (in thousands):


Remainder of 2014	$	4,334
2015		8,631
2016		8,643
2017		8,631
2018		5,325
2019		983

	$	36,547

Long-Term Cash Incentive Awards

During the six months ended June 30, 2014, the Compensation Committee of the Board of Directors approved providing long-term cash incentive awards of up to $15.0 million for non-officer employees. A total of $13.5 million has been awarded to current employees. These awards will vest on April 1, 2017. Compensation expense for the long-term cash incentive awards was $1.2 million for both the three and six months ended June 30, 2014.

Note 11. Supplemental Information to Condensed Statements of Cash Flows

The following table summarizes interest and income taxes paid for the periods presented (in thousands):


	Six Months Ended June 30,
	2014		2013
Interest paid (net of capitalized interest of $135,578 and $166,443, respectively)	$	14,623	$	—
Income taxes paid, net	$	386	$	181

Supplemental Non-Cash Investing and Financing Activities

Total payables included in accrued liabilities related to acquisition and drilling expenditures for oil and gas properties for the Company were $77.5 million and $47.6 million at June 30, 2014 and 2013, respectively. Non-cash investing activities associated primarily with tubular oil and gas equipment were approximately $10.6 million and $24.4 million for the six months ended June 30, 2014 and 2013, respectively.

Note 12. Commitments and Contingencies

Commitments

Operating Leases

We lease corporate office space in Tulsa, Oklahoma, Denver, Colorado and Houston, Texas, as well as a number of other field office locations. We recorded rental expense of approximately $3.2 million and $2.8 million for the six months ended June 30, 2014 and 2013, respectively. Rental expense is included in general and administrative expenses in the condensed consolidated statements of income (loss) and comprehensive income (loss).

Other Commercial Commitments

We have commitments for drilling rigs and related equipment with payments under the contracts accounted for as capital additions to our oil and gas properties. As of June 30, 2014, future payments under these agreements, including rig terminations, are approximately $22.3 million for the remainder of 2014.

Letters of Credit and Bonds

As of June 30, 2014, we had outstanding irrevocable letters of credit totaling approximately $1.8 million to guarantee payment of certain marketing related and workers compensation insurance obligations. Additionally, at June 30, 2014, we had approximately $10.6 million in outstanding bonds securing various commitments, such as plugging costs and surface damages.

Change in Control Agreements

Effective January 1, 2014, the Company adopted a Change in Control Severance Plan for non-officer employees that applies to eligible employees and a Change in Control Severance Plan for officers (collectively, the “Change in Control Severance Plans”) that applies to all officers except the Chief Executive Officer, who is covered by an employment agreement. The Change in Control Severance Plans provide for the payment of cash compensation and certain other benefits to eligible officers and non-officer employees in the event of a change in control and a qualifying termination of employment. The obligations under the Change in Control Severance Plans are generally based on the terminated employee’s cash compensation, employment tenure, and position within the Company.

An employment agreement with our Chief Executive Officer provides for the payment of cash compensation and certain other benefits in the event of a severance or change in control depending upon the circumstance.

Depending on the facts and circumstances associated with a potential change in control, the total payments made pursuant to the Change in Control Severance Plans or employment agreements could be material.

Litigation and Contingencies

We are involved in various matters incidental to our operations and business that might give rise to a loss contingency, including, among other things, legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental or other matters. In addition, we are subject, from time to time, to customary audits and investigations by governmental and tribal authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as our compliance with unclaimed property (escheatment) requirements and other laws. Unclaimed property laws generally require us to turn over to certain governmental authorities the property of others held by us that has been unclaimed for a specified period of time. In addition, other parties with an interest in wells operated by us have the ability under various contractual agreements to perform audits of our joint interest billing practices where we receive reimbursements from these owners for their share of the costs incurred in connection with the oil and gas properties that we operate.

We vigorously defend ourselves in these matters, including through the retention of outside counsel where appropriate. A loss contingency may take the form of (i) overtly threatened or pending litigation, (ii) a contractually assumed obligation, or (iii) an unasserted possible claim or assessment. For these matters, we review the merits of the asserted claims, consult with internal and outside counsel as appropriate, assess the degree of probability of an unfavorable outcome, consider possible legal, administrative, litigation, and resolution or settlement strategies, and the availability of insurance coverage, subrogation, indemnities and potential third party liabilities.

If we determine that an unfavorable outcome or loss of a particular matter is probable and the amount of the loss can be reasonably estimated, we accrue a liability for the contingent obligation, as well as any expected insurance recovery amounts up to the accrued loss. Recovery of any amount in excess of the related recorded contingent loss is recognized if and when all contingencies related to the recovery have been resolved. As new information becomes available as a result of activities in such matters, legal or administrative rulings in similar matters or a change in applicable law, our conclusions regarding the probability of outcomes and estimated loss may change. The impact of subsequent changes to our accruals may have a material effect on our results of operations reported in a single period. We expense all legal fees in the period the expenses are incurred.

In matters where litigation is pending, it is common and often required for the parties to attend non-binding mediations or settlement conferences. Such mediations or conferences can end in settlement of litigation matters. We have participated in such non-binding mediation and subsequent discussions in an action seeking class certification and damages related to royalty payments for wells located in Oklahoma. In December 2013, a settlement with the plaintiffs was approved by the court. At December 31, 2013, an accrual for this matter was recorded in our consolidated balance sheet. Settlement payments totaling $15.2 million were made in the first quarter of 2014.

In 2014, in connection with an ongoing audit on behalf of a federal regulator, we began a process of reviewing the manner in which our obligations to make royalty payments for natural gas production on federal leases should be determined. The process involves attempting to determine components of certain fees we pay to transport and process some of our natural gas production associated with individual federal leases and evaluate how each component impacts our royalty payment obligations. We estimate that this process will result in additional royalty payments made related to natural gas production on certain federal leases and have recorded a liability associated with this matter. Estimating the liability is inherently uncertain as each contract associated with individual federal leases has to be analyzed and the estimated fee components will ultimately be subject to approval by our federal regulator. Consequently, it is reasonably possible that a loss exceeding the liability recorded has been incurred and we cannot estimate the range of loss in excess of our recorded liability. However, we do not currently expect our payment of additional royalties will be materially in excess of the liability recorded.

Also in 2014, an audit of our unclaimed property (escheat) practices in certain states was commenced. As is customary in the industry, we do not expect preliminary audit results to be known for several months.

As of June 30, 2014, our total accrual for all loss contingencies was $7.0 million, of which $1.3 million was included in oil and natural gas revenues held for distribution and $5.7 million was included in accrued and other current liabilities in our condensed consolidated balance sheet. Because of the uncertainty inherent in estimating probable payments associated with loss contingencies, it is reasonably possible that adjustments to our accrual will change as facts and circumstances change and such changes may be material.

Note 13. Income Taxes

Samson is subject to corporate income taxes. Income tax expense (benefit) for the periods presented consisted of the following (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Current taxes:
Federal	$	—		$	—		$	—		$	—
State		155			(99	)		155			(99	)
Deferred taxes:
Federal		(113,009	)		45,176			(113,449	)		13,462
State		(2,292	)		955			(2,301	)		284

Income tax provision (benefit)	$	(115,146	)	$	46,032		$	(115,595	)	$	13,647

Total income tax expense or benefit differed from the amounts computed by applying the U.S. federal income tax rate to net income (loss) from continuing operations before income taxes as a result of the following:


	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
U.S. statutory rate		35%		35%		35%		35%
State taxes		1%		1%		1%		1%
Other		0%		0%		0%		0%

		36%		36%		36%		36%

We evaluated our tax positions and concluded that we have not taken any uncertain tax positions that require an adjustment to the financial statements. Tax penalties and related interest would be charged to the provision for income taxes when uncertain tax positions are recorded in the financial statements. Therefore, there are no related accruals for interest and penalties related to unrecognized tax benefits at June 30, 2014.

Note 14. Related Party Transactions

We have a consulting agreement with affiliates of KKR, our principal shareholder, and other initial equity investors pursuant to which we receive management services and incur a quarterly management fee. At the commencement of the agreement in 2012, the aggregate annual fee was $20.0 million, resulting in a quarterly fee of $5.0 million. As required by the agreement, the aggregate annual fee and corresponding quarterly fee increases 5.0% each year. We incurred $5.5 million and $5.3 million in the three months ended June 30, 2014 and 2013, respectively, and $11.0 million and $10.5 million in the six months ended June 30, 2014 and 2013, respectively. These fees are included in the condensed consolidated statements of income (loss) and comprehensive income (loss) as related party management fee.

Effective February 10, 2012, we entered into a Gas Offtake Rights Agreement (the “Offtake Agreement”) with Trademark Merchant Energy, LLC (“TME”) granting TME the right to acquire a percentage of the natural gas delivered to specified delivery points at an adjusted index price. ITOCHU Corporation (“ITOCHU”), a minority owner of Samson’s common stock, controls TME and is party to the Offtake Agreement. During 2013, the Offtake Agreement was assigned to another affiliate of ITOCHU. Total gross receipts under the Offtake Agreement were approximately $36.6 million for the six months ended June 30, 2013. There were no receipts under the Offtake Agreement for the three and six months ended June 30, 2014.

KKR Capstone Consulting, LLC (“Capstone”) is a consulting company of operational professionals that works exclusively with KKR’s portfolio company management teams. During the three months ended June 30, 2014 and 2013, we incurred costs of approximately $0.1 million and $0.6 million, respectively, and $0.2 million and $1.3 million for the six months ended June 30, 2014 and 2013, respectively, to Capstone for consulting services it provided to us.

We also, from time to time, purchase pipe and pumping supplies from Bell Supply Company LLC, which is an affiliate of Crestview Partners II GP, L.P. One of our directors serves on the board of directors of the parent to Bell Supply Company LLC. For the three months ended June 30, 2014 and 2013, we incurred approximately $0.2 million and $0.6 million, respectively, and $0.5 million and $1.2 million for the six months ended June 30, 2014 and 2013, respectively, for supplies from Bell Supply Company LLC.

Note 15. Condensed Consolidating Financial Information

Samson Resources Corporation and specified 100% owned subsidiaries (Geodyne Resources, Inc., Samson Contour Energy Co., Samson Contour Energy E&P, LLC, Samson Holdings, Inc., Samson Lone Star, LLC, Samson Resources Company, and Samson-International, Ltd. (collectively the “Subsidiary Guarantors” and, together with Samson Resources Corporation, the “Guarantors”)) of Samson Investment Company (the “Issuer”), a 100% owned subsidiary of Samson Resources Corporation, fully and unconditionally guarantee obligations under the Senior Notes. These guarantees are joint and several obligations of the Guarantors.

Any guarantee by a Subsidiary Guarantor will be automatically and unconditionally released and discharged upon (1)(A) the sale, exchange or transfer of the capital stock of the Subsidiary Guarantor or (B) the sale, exchange or transfer of all, or substantially all, of the assets of such Subsidiary Guarantor, (2) the release or discharge of the guarantee by the Subsidiary Guarantor with respect to the RBL Revolver, (3) the designation of it as an “Unrestricted Subsidiary” in compliance with the indenture governing the Senior Notes, (4) the legal or covenant defeasance or discharge of the indenture governing the Senior Notes or (5) the merger or consolidation of any Subsidiary Guarantor with and into the Issuer or another Guarantor, all in compliance with the provisions of the indenture governing the Senior Notes. There are no release provisions under the indenture governing the Senior Notes with respect to the parent guarantee provided by Samson Resources Corporation.

We have prepared condensed consolidating financial statements in order to quantify assets, results of operations and cash flows of Samson Resources Corporation, the Issuer, the Subsidiary Guarantors and non-guarantor subsidiaries. The following condensed consolidating balance sheets, condensed consolidating statements of income (loss) and comprehensive income (loss) and condensed consolidating statements of cash flows for the periods presented, present financial information for Samson Resources Corporation, as the parent of the Issuer on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the Issuer on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the Subsidiary Guarantors on a stand-alone basis, the financial information of our non-guarantor subsidiaries on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the financial information on a condensed consolidated basis. As Samson Resources Corporation, the Issuer, and the Subsidiary Guarantors are separate taxable entities, income taxes are provided with respect to the individual operations of each entity (excluding any equity pick up) only, and deferred income taxes are recorded separately.

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF JUNE 30, 2014

(In thousands)


	Samson Resources Corporation (Parent Guarantor)		Samson Investment Company (Issuer)		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	254	$	12,894	$	162	$	—		$	13,310
Accounts receivable, net		—		—		217,564		—		—			217,564
Intercompany receivables		4,088		83,269		—		—		(87,357	)		—
Other current assets		—		36		52,271		—		—			52,307
Oil and gas properties, net		—		—		6,631,068		—		—			6,631,068
Other property and equipment		—		—		295,680		—		—			295,680
Investment in subsidiaries		1,492,861		4,901,370		—		—		(6,394,231	)		—
Other non-current assets		21,677		350,238		18,973		30,359		(275,294	)		145,953

Total assets	$	1,518,626	$	5,335,167	$	7,228,450	$	30,521	$	(6,756,882	)	$	7,355,882

Accounts payable	$	—	$	—	$	35,914	$	29	$	—		$	35,943
Intercompany payables		—		—		59,744		27,613		(87,357	)		—
Accrued and other current liabilities		—		92,306		230,429		1,614		—			324,349
Other current liabilities		—		—		190,935		—		—			190,935
Long-term debt		—		3,750,000		—		—		—			3,750,000
Deferred income tax liabilities		—		—		1,725,000		—		(275,294	)		1,449,706
Cumulative preferred stock subject to mandatory redemption		196,859		—		—		—		—			196,859
Puttable common stock		1,000		—		—		—		—			1,000
Other non-current liabilities		—		—		86,323		—		—			86,323
Shareholders’ equity		1,320,767		1,492,861		4,900,105		1,265		(6,394,231	)		1,320,767

Total liabilities and shareholders’ equity	$	1,518,626	$	5,335,167	$	7,228,450	$	30,521	$	(6,756,882	)	$	7,355,882

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2013

(In thousands)


	Samson Resources Corporation (Parent Guarantor)		Samson Investment Company (Issuer)		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	238	$	399	$	90	$	—		$	727
Accounts receivable, net		10		—		174,979		—		—			174,989
Intercompany receivables		—		22,204		19,791		—		(41,995	)		—
Other current assets		—		14,392		30,192		52		—			44,636
Oil and gas properties, net		—		—		6,738,239		—		—			6,738,239
Other property and equipment		—		—		302,693		—		—			302,693
Investment in subsidiaries		1,696,448		5,051,279		—		—		(6,747,727	)		—
Other non-current assets		10,569		309,373		71,296		53,230		(268,066	)		176,402

Total assets	$	1,707,027	$	5,397,486	$	7,337,589	$	53,372	$	(7,057,788	)	$	7,437,686

Accounts payable	$	—	$	—	$	36,255	$	12	$	—		$	36,267
Intercompany payables		—		—		—		41,995		(41,995	)		—
Accrued and other current liabilities		—		95,268		244,046		1,920		—			341,234
Other current liabilities		—		40,529		117,296		—		—			157,825
Long-term debt		—		3,554,000		—		—		—			3,554,000
Deferred income tax liabilities		—		—		1,824,483		7,558		(268,066	)		1,563,975
Cumulative preferred stock subject to mandatory redemption		191,035		—		—		—		—			191,035
Puttable common stock		3,250		—		—		—		—			3,250
Other non-current liabilities		—		11,241		66,117		—		—			77,358
Shareholders’ equity		1,512,742		1,696,448		5,049,392		1,887		(6,747,727	)		1,512,742

Total liabilities and shareholders’ equity	$	1,707,027	$	5,397,486	$	7,337,589	$	53,372	$	(7,057,788	)	$	7,437,686

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF INCOME (LOSS) AND

COMPREHENSIVE INCOME (LOSS)

FOR THE THREE MONTHS ENDED JUNE 30, 2014

(In thousands)


	Samson Resources Corporation (Parent Guarantor)			Samson Investment Company (Issuer)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Total revenues	$	—		$	—		$	260,798		$	—		$	—	$	260,798
Total operating expenses		5,719			(225	)		556,635			123			—		562,252

Operating income (loss)		(5,719	)		225			(295,837	)		(123	)		—		(301,454	)
Interest expense, net		(856	)		(20,532	)		(55	)		—			—		(21,443	)
Equity in earnings of subsidiaries		(203,909	)		(191,863	)		—			—			395,772		—
Other income (expense), net		—			—			(71	)		—			—		(71	)

Income (loss) before income taxes		(210,484	)		(212,170	)		(295,963	)		(123	)		395,772		(322,968	)
Income tax provision (benefit)		(2,662	)		(8,261	)		(104,159	)		(64	)		—		(115,146	)

Net income (loss)		(207,822	)		(203,909	)		(191,804	)		(59	)		395,772		(207,822	)
Total other comprehensive income (loss)		(4,490	)		(4,490	)		(4,490	)		—			8,980		(4,490	)

Total comprehensive income (loss)	$	(212,312	)	$	(208,399	)	$	(196,294	)	$	(59	)	$	404,752	$	(212,312	)

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF INCOME (LOSS) AND

COMPREHENSIVE INCOME (LOSS)

FOR THE THREE MONTHS ENDED JUNE 30, 2013

(In thousands)


	Samson Resources Corporation (Parent Guarantor)			Samson Investment Company (Issuer)		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues	$	—		$	—	$	375,620	$	316	$	—		$	375,936
Total operating expenses		5,535			—		242,456		274		—			248,265

Operating income (loss)		(5,535	)		—		133,164		42		—			127,671
Interest income, net		—			—		—		8		—			8
Equity in earnings of subsidiaries		86,629			86,629		—		—		(173,258	)		—
Other (expense) income, net		—			—		1,396		1		—			1,397

Income (loss) before income taxes		81,094			86,629		134,560		51		(173,258	)		129,076
Income tax provision (benefit)		(1,950	)		—		47,960		22		—			46,032

Net income (loss)		83,044			86,629		86,600		29		(173,258	)		83,044
Total other comprehensive income (loss)		23,854			23,854		23,854		—		(47,708	)		23,854

Total comprehensive income (loss)	$	106,898		$	110,483	$	110,454	$	29	$	(220,966	)	$	106,898

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF INCOME (LOSS) AND

COMPREHENSIVE INCOME (LOSS)

FOR THE SIX MONTHS ENDED JUNE 30, 2014

(In thousands)


	Samson Resources Corporation (Parent Guarantor)			Samson Investment Company (Issuer)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Total revenues	$	—		$	—		$	511,726		$	—		$	—	$	511,726
Total operating expenses		11,367			—			782,344			332			—		794,043

Operating income (loss)		(11,367	)		—			(270,618	)		(332	)		—		(282,317	)
Interest expense, net		(1,456	)		(40,378	)		(85	)		—			—		(41,919	)
Equity in earnings of subsidiaries		(200,590	)		(174,598	)		—			—			375,188		—
Other income (expense), net		—			—			(6	)		(197	)		—		(203	)

Income (loss) before income taxes		(213,413	)		(214,976	)		(270,709	)		(529	)		375,188		(324,439	)
Income tax provision (benefit)		(4,569	)		(14,386	)		(96,452	)		(188	)		—		(115,595	)

Net income (loss)		(208,844	)		(200,590	)		(174,257	)		(341	)		375,188		(208,844	)
Total other comprehensive income (loss)		(10,344	)		(10,344	)		(10,344	)		—			20,688		(10,344	)

Total comprehensive income (loss)	$	(219,188	)	$	(210,934	)	$	(184,601	)	$	(341	)	$	395,876	$	(219,188	)

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF INCOME (LOSS) AND

COMPREHENSIVE INCOME (LOSS)

FOR THE SIX MONTHS ENDED JUNE 30, 2013

(In thousands)


	Samson Resources Corporation (Parent Guarantor)			Samson Investment Company (Issuer)		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	—	$	587,621	$	1,216		$	—		$	588,837
Total operating expenses		10,806			—		538,657		1,302			—			550,765

Operating loss		(10,806	)		—		48,964		(86	)		—			38,072
Interest income, net		—			—		—		13			—			13
Equity in earnings of subsidiaries		31,787			31,787		—		—			(63,574	)		—
Other (expense) income, net		—			—		2,053		(1,676	)		—			377

Income (loss) before income taxes		20,981			31,787		51,017		(1,749	)		(63,574	)		38,462
Income tax provision (benefit)		(3,834	)		—		18,102		(621	)		—			13,647

Net income (loss)		24,815			31,787		32,915		(1,128	)		(63,574	)		24,815
Total other comprehensive income (loss)		1,004			1,004		1,004		—			(2,008	)		1,004

Total comprehensive income (loss)	$	25,819		$	32,791	$	33,919	$	(1,128	)	$	(65,582	)	$	25,819

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2014

(In thousands)


	Samson Resources Corporation (Parent Guarantor)			Samson Investment Company (Issuer)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(11,535	)	$	(14,112	)	$	286,255		$	(206	)	$	—		$	260,402
Investing activities:
Capital expenditures—oil and gas properties		—			—			(484,875	)		—			—			(484,875	)
Capital expenditures—other property and equipment		—			—			(9,275	)		—			—			(9,275	)
Proceeds from divestitures—oil and gas properties		—			—			53,418			—			—			53,418
Proceeds (purchase) of other assets		—			—			70			—			—			70
Advances to parent/subsidiary		—			(180,905	)		—			—			180,905			—

Net cash provided by (used in) investing activities		—			(180,905	)		(440,662	)		—			180,905			(440,662	)

Financing activities:
Advances from issuer		13,725			—			166,902			278			(180,905	)		—
Proceeds from revolver		—			264,000			—			—			—			264,000
Repayment of revolver		—			(68,000	)		—			—			—			(68,000	)
Debt issuance cost		—			(967	)		—			—			—			(967	)
Repurchase of puttable common stock		(2,190	)		—			—			—			—			(2,190	)

Net cash provided by financing activities		11,535			195,033			166,902			278			(180,905	)		192,843

Net change in cash		—			16			12,495			72			—			12,583
Cash and cash equivalents at beginning of period		—			238			399			90			—			727

Cash and cash equivalents at end of period	$	—		$	254		$	12,894		$	162		$	—		$	13,310

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2013

(In thousands)


	Samson Resources Corporation (Parent Guarantor)			Samson Investment Company (Issuer)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(101	)	$	(94	)	$	352,062		$	(19,555	)	$	—		$	332,312
Investing activities:
Capital expenditures—oil and gas properties		—			—			(509,545	)		—			—			(509,545	)
Capital expenditures—other property and equipment		—			—			(23,785	)		—			—			(23,785	)
Proceeds from divestitures—oil and gas properties		—			—			107,422			—			—			107,422
Proceeds (purchase) of other assets		—			—			2,021			—			—			2,021
Advances to parent/subsidiary		—			(134,757	)		—			—			134,757			—

Net cash provided by (used in) investing activities		—			(134,757	)		(423,887	)		—			134,757			(423,887	)

Financing activities:
Proceeds from revolver		—			215,000			—			—			—			215,000
Repayment of revolver		—			(80,000	)		—			—			—			(80,000	)
Repurchase of puttable common stock		(950	)		—			—			—			—			(950	)
Advances from issuer		1,051			—			111,986			21,720			(134,757	)		—

Net cash provided by financing activities		101			135,000			111,986			21,720			(134,757	)		134,050

Net change in cash		—			149			40,161			2,165			—			42,475
Cash and cash equivalents at beginning of period		—			1,656			1,155			228			—			3,039

Cash and cash equivalents at end of period	$	—		$	1,805		$	41,316		$	2,393		$	—		$	45,514

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis in conjunction with our condensed consolidated financial statements and accompanying notes included under Part I, Item 1—“Financial Statements” of this report, as well as our consolidated financial statements, accompanying notes and the discussion under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Prospectus. This discussion and analysis contains forward-looking statements regarding industry outlook, our expectations regarding our future performance, liquidity and capital resources and other non-historical statements that are based on management’s current expectations, estimates and projections about our business and operations. Our actual results may differ materially from those contained in, or implied by, any forward-looking statements. These forward-looking statements are subject to numerous risks and uncertainties, including, but not limited to, the risks and uncertainties described and referenced in the “Cautionary Statement Regarding Forward-Looking Statements” section of this report.

Overview

We are an independent oil and gas company engaged in the exploration, development and production of oil and gas properties located onshore in the United States. We operate our business and properties through our West Division, which includes properties primarily in the Rocky Mountains region, and our East Division, which includes properties primarily in the Mid-Continent and East Texas regions.

We expect to grow our business by leveraging our management team’s experience in building a focused portfolio of core exploration and development assets capable of sustaining a long term drilling plan which achieves predictable and profitable production growth. We expect to selectively pursue acquisitions and divestitures that meet our strategic and financial objectives. At June 30, 2014, we had approximately 1.7 million net acres under lease, contract or other means of ownership and control.

We strive to achieve growth through a disciplined, returns-focused approach to capital spending. The focus of our drilling program is to increase our oil and NGL production, which we believe will result in a more balanced portfolio and increased profits. Although we are currently focusing our drilling activities to develop properties with oil and NGL production, we have a significant amount of undeveloped properties with leases held by current production that we believe contain substantial natural gas reserves from which we could realize value in the event of future increases in natural gas prices.

Recent Developments

Portfolio management

We continue to divest our non-core assets. During the six months ended June 30, 2014, we divested approximately 500 gross (70 net) wells with an average net daily production of approximately 3,400 Mcfe/d, and have received approximately $51.4 million associated with these divestitures.

In addition, consistent with our comprehensive growth strategy of focusing on a portfolio of core assets capable of supporting a long-term, sustainable drilling program, we are actively considering more substantial divestitures and other asset monetization transactions with respect to assets that we do not believe meet our strategic objectives. These transactions may involve significant asset positions or entire business units. Depending upon the success, timing and structure of any such transactions, the amount of proceeds we receive from portfolio management activity could materially increase during the remainder of 2014. In conjunction with our consideration of more substantial divestitures, we are also considering substantial acquisitions that further our comprehensive growth strategy.

Long-term debt

In May 2014, we amended the credit agreement governing the RBL Revolver to, among other things, (i) modify the financial performance covenant for 2014 and 2015, (ii) reduce the borrowing base from approximately $1.8 billion to $1.0 billion and (iii) permit us to incur an additional $500.0 million of second lien debt without a further, related reduction to the borrowing base, subject to certain limitations and conditions. The amendment resulted in improved short term liquidity as the new financial performance covenant provides increased financial flexibility.

Information system enhancements

We have recently implemented a new enterprise resource planning (“ERP”) system, which will improve our business management and reporting capabilities. We began transacting with our new ERP system on January 1, 2014.

Basis of Presentation

The following discussion and analysis addresses significant changes in our results of operations and capital resources for the three and six month periods ended June 30, 2014, as compared to the three and six month periods ended June 30, 2013, and in our financial condition and liquidity since December 31, 2013. This section should be read in conjunction with our unaudited condensed consolidated financial statements and notes included elsewhere in this report and our audited consolidated financial statements and notes included in the Prospectus.

Market Conditions

Prices for our products significantly impact our revenue, net income (loss) and cash flows. Oil, natural gas and NGLs are commodities, and prices for commodities are inherently volatile. The following table sets forth the average market price for natural gas and oil for the three and six months ended June 30, 2014 and 2013:


	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Average prices:
Natural gas (MMBtu) (a)	$	4.67	$	4.09	$	4.80	$	3.71
Oil (Bbl) (b)	$	102.99	$	94.22	$	100.84	$	94.30

(a)	Based on NYMEX last day settlements.

(b)	Based on NYMEX calendar month average settlements.

Results of Operations

Oil, Natural Gas and NGL Revenue

Our oil, natural gas and NGL revenues are derived from the sale of oil, natural gas and NGLs and do not include the effects of the settlements of our derivative positions. The following tables set forth information regarding our revenues for the three and six months ended June 30, 2014 and 2013 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Crude oil	$	116,937	$	129,428	$	229,064	$	242,356
Natural gas		142,740		139,727		292,783		256,824
NGLs		39,377		34,814		85,465		67,699

Total revenue	$	299,054	$	303,969	$	607,312	$	566,879

Revenues for the three months ended June 30, 2014 were down approximately 1.6% as a result of lower crude oil and natural gas production, which contributed to an overall decline in production of 8.7%, partially offset by higher realized pricing on crude oil, natural gas and NGL sales. Revenues for the six months ended June 30, 2014 increased by 7.1% primarily as a result of improvements in crude oil, natural gas and NGL realized pricing as well as higher NGL production, partially offset by declines in crude oil and natural gas production.

The following tables summarize the impact of price and volume changes on our revenues during the three and six months ended June 30, 2014 (in thousands):


	Crude Oil			Natural Gas			NGLs		Total
Revenue for the three months ended June 30, 2013	$	129,428		$	139,727		$	34,814	$	303,969
Change due to volumes		(16,584	)		(15,133	)		406		(31,311	)
Change due to price		4,093			18,146			4,157		26,396

Revenue for the three months ended June 30, 2014	$	116,937		$	142,740		$	39,377	$	299,054


	Crude Oil			Natural Gas			NGLs		Total
Revenue for the six months ended June 30, 2013	$	242,356		$	256,824		$	67,699	$	566,879
Change due to volumes		(22,363	)		(41,184	)		4,990		(58,557	)
Change due to price		9,071			77,143			12,776		98,990

Revenue for the six months ended June 30, 2014	$	229,064		$	292,783		$	85,465	$	607,312

Pricing

The following table sets forth information regarding average realized sales prices for the three and six months ended June 30, 2014 and 2013:


	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Change			2014		2013		Change
Average realized sales prices:
Crude oil, unhedged ($/Bbl)	$	94.44	$	91.55		3	%	$	93.10	$	89.74		4	%
Natural gas, unhedged ($/Mcfe)	$	4.09	$	3.62		13	%	$	4.29	$	3.30		30	%
NGLs, unhedged ($/Bbl)	$	33.30	$	29.75		12	%	$	36.40	$	30.62		19	%

Average realized price, unhedged ($/Mcfe)	$	6.05	$	5.62		8	%	$	6.26	$	5.28		18	%

Crude oil, hedged ($/Bbl) (a)	$	79.46	$	90.10		(12	)%	$	80.74	$	88.20		(8	)%
Natural gas, hedged ($/Mcfe) (a)	$	3.67	$	3.35		10	%	$	3.76	$	3.35		12	%
NGLs, hedged ($/Bbl) (a)	$	31.84	$	31.24		2	%	$	33.99	$	32.11		6	%

Average realized price, hedged ($/Mcfe)	$	5.34	$	5.42		(1	)%	$	5.51	$	5.31		4	%

(a)	The effects of hedges include cash settlements for both derivatives designated as cash flow hedges and those not designated as cash flow hedges.

Natural Gas Prices

Natural gas prices are subject to variances based on local supply and demand conditions as well as rapidly evolving market conditions. A significant majority of our natural gas sales contracts are based upon index pricing that varies widely based upon many factors, such as geography. Most of our natural gas is sold on a monthly basis based upon a monthly index price or a daily basis based upon daily market prices for a given period. Our average realized natural gas price increased for the three and six months ended June 30, 2014 primarily as a result of higher market pricing.

We primarily utilize fixed price swaps and collars, and occasionally basis swaps, to manage our exposure to fluctuations in natural gas prices. For the three and six months ended June 30, 2014, approximately 79% and 81%, respectively, of our natural gas production was economically hedged with financial derivatives.

Crude Oil Prices

The majority of our crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. These factors include supply disruptions, pipeline and refinery outages, weather patterns and global events and economics. Most of our crude oil is sold on a monthly basis based upon a variable differential to NYMEX that fluctuates based upon regional fundamentals. Our realized crude oil price for the three and six months ended June 30, 2014 increased as a result of these market forces.

We utilize fixed price swaps to manage our exposure to crude oil prices. For the three and six months ended June 30, 2014, the notional amount of our crude oil hedges exceeded our actual production. Consequently, realized losses on our crude oil hedges decreased our realized hedged crude oil pricing.

NGL Prices

Our NGLs are sold based upon published monthly average market pricing less a deduction for transportation and fractionation. Recently, there has been significant volatility in NGL pricing. That volatility has a significant impact on our realized price for NGLs. Additionally, the market price of our NGL production, which primarily consists of ethane, propane, butane, iso-butane and natural gasoline, can be significantly impacted by local market conditions, such as fractionation availability and business conditions of the end users of such NGL products, such as chemical companies, plastic manufacturers and propane dealers. Our average realized NGL price increased for the three and six months ended June 30, 2014 primarily as a result of harsh winter conditions, which significantly increased the price for propane in the first quarter of 2014, as well as increased crude oil and natural gas prices, which are correlated with the price we receive for our NGL production.

We utilize fixed price swaps to manage our exposure to NGL pricing. For the three and six months ended June 30, 2014, approximately 58% and 56%, respectively, of our NGL production was economically hedged with financial derivatives.

Commodity Derivatives

We utilize commodity-based derivative instruments to manage our exposure to changes in expected future cash flows from forecasted sales of oil, natural gas and NGLs. All of our derivative activity is designed to reduce our exposure to declining prices. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, and to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses. Changes in the fair value of derivative instruments not designated as accounting hedges are recognized in commodity derivatives, net in our condensed consolidated statements of income (loss) and comprehensive income (loss) in the periods in which they occur. Accordingly, this could result in future earnings that are more volatile.

We have designated a portion of our derivatives as cash flow hedges for accounting purposes. The effective portion of changes in fair values of our derivatives designated as cash flow hedges are recorded through other comprehensive income (loss) and do not impact net income (loss) until the underlying physical transaction settles. Once the underlying physical transaction settles, the cash settlement gain or loss on the related cash flow hedge is recorded as commodity derivatives, net, in our condensed consolidated statements of income (loss) and comprehensive income (loss). Any change in the fair value of cash flow hedges resulting from ineffectiveness is recognized in current earnings in commodity derivatives, net.

The following table sets forth the components of the composition of our commodity derivatives, net in our condensed consolidated statements of income (loss) and comprehensive income (loss) (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Cash settlements:
Gas derivatives	$	(14,703	)	$	(10,574	)	$	(36,581	)	$	4,123
Oil derivatives		(18,549	)		(2,039	)		(30,413	)		(4,183	)
NGL derivatives		(1,725	)		1,789			(5,676	)		3,295

Total cash settlements		(34,977	)		(10,824	)		(72,670	)		3,235

Total gains (losses) on derivatives:
Gas derivatives		7,999			65,406			(9,715	)		19,098
Oil derivatives		(11,448	)		10,897			(15,309	)		(2,538	)
NGL derivatives		170			5,646			2,108			1,377

Total gains (losses) on derivatives		(3,279	)		81,949			(22,916	)		17,937

Ineffectiveness recorded on cash flow hedges		—			842			—			786

Total commodity derivatives, net	$	(38,256	)	$	71,967		$	(95,586	)	$	21,958

Production

The following table sets forth information regarding our average net daily production for the three and six months ended June 30, 2014 and 2013:


	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Change			2014		2013		Change
Production volumes:
Natural gas (MMcf/d):
West Division
Williston		2		—		2			2		—		2
Powder River		2		2		—			2		2		—
Greater Green River		39		58		(19	)		36		53		(17	)
San Juan		80		94		(14	)		82		96		(14	)
East Division
Mid-Continent West		51		52		(1	)		49		52		(3	)
Mid-Continent East		73		68		5			74		68		6
East Texas		135		148		(13	)		130		156		(26	)
Other (a)		2		2		—			2		2		—

Total		384		424		(40	)		377		429		(52	)

Crude oil (Bbl/d):
West Division
Williston		3,492		4,465		(973	)		3,448		4,223		(775	)
Powder River		4,207		3,313		894			3,680		3,430		250
Greater Green River		823		1,186		(363	)		847		1,016		(169	)
San Juan		2		—		2			1		—		1
East Division
Mid-Continent West		1,794		3,241		(1,447	)		2,036		3,150		(1,114	)
Mid-Continent East		2,065		1,853		212			2,371		1,522		849
East Texas		1,177		1,350		(173	)		1,167		1,436		(269	)
Other (a)		48		129		(81	)		42		142		(100	)

Total		13,608		15,537		(1,929	)		13,592		14,919		(1,327	)

NGL (Bbl/d):
West Division
Williston		259		16		243			211		17		194
Powder River		176		216		(40	)		161		209		(48	)
Greater Green River		3,260		3,936		(676	)		3,116		3,262		(146	)
San Juan		—		9		(9	)		24		14		10
East Division
Mid-Continent West		3,767		3,873		(106	)		3,809		3,831		(22	)
Mid-Continent East		2,918		1,799		1,119			3,036		1,783		1,253
East Texas		2,603		3,002		(399	)		2,580		3,088		(508	)
Other (a)		12		9		3			34		11		23

Total		12,995		12,860		135			12,971		12,215		756

Total Liquids (Bbl/d):
West Division
Williston		3,751		4,481		(730	)		3,660		4,240		(580	)
Powder River		4,383		3,529		854			3,841		3,639		202
Greater Green River		4,083		5,122		(1,039	)		3,963		4,278		(315	)
San Juan		2		9		(7	)		25		15		10
East Division
Mid-Continent West		5,560		7,115		(1,555	)		5,845		6,981		(1,136	)
Mid-Continent East		4,983		3,652		1,331			5,407		3,305		2,102
East Texas		3,780		4,352		(572	)		3,747		4,524		(777	)
Other (a)		60		139		(79	)		77		153		(76	)

Total		26,602		28,399		(1,797	)		26,565		27,135		(570	)

Combined Production (MMcfe/d):
West Division
Williston		24		27		(3	)		24		26		(2	)
Powder River		29		24		5			25		24		1
Greater Green River		64		89		(25	)		60		78		(18	)
San Juan		80		94		(14	)		82		96		(14	)
East Division
Mid-Continent West		84		94		(10	)		84		94		(10	)
Mid-Continent East		103		90		13			107		88		19
East Texas		157		175		(18	)		153		184		(31	)
Other (a)		2		3		(1	)		2		3		(1	)

Total		543		596		(53	)		537		593		(56	)

(a)	Other reflects our interests in certain non-core assets located throughout the continental United States.

Natural Gas Production

Natural gas production decreased 9.6% and 12.3% for the three and six months ended June 30, 2014, respectively. The decrease in natural gas production volumes was primarily in our Greater Green River, San Juan and East Texas business units. Production declines in these business units were primarily due to the divestiture of properties in our Greater Green River business unit and normal decline associated with the curtailing of capital investment projects in areas that have a lower concentration of oil and NGLs, such as the San Juan Basin and the Haynesville Shale formation.

Crude Oil Production

Crude oil production decreased 12.4% and 8.9% for the three and six months ended June 30, 2014, respectively. The decrease in crude oil production was primarily due to reduced drilling activity in our Williston and Mid-Continent West business units. Also contributing to the decrease in oil production were divestitures of properties in our Williston business unit as well as divested Permian properties in our East Texas business unit. Partially offsetting these production declines were higher production volumes in our Powder River and Mid-Continent East business units. Increased production volumes in these business units were primarily due to drilling activity focusing on the Shannon, Sussex, and Marmaton formations.

NGL Production

NGL production increased 1.0% and 6.2% for the three and six months ended June 30, 2014, respectively. The increase in NGL production was primarily in our Williston and Mid-Continent East business units. Production increases in these business units were primarily due to pipeline connections in the Williston Basin and drilling activity in the Marmaton formation. These increases were partially offset by reduced liquids production from wells in our Greater Green River business unit and ethane rejection in the Carthage field of our East Texas business unit. We expect to continue to focus on areas which contain natural gas with higher concentrations of NGLs as part of our core drilling program.

Operating Expenses

The following tables set forth information regarding operating expenses for the three and six months ended June 30, 2014 and 2013 (in thousands, except per unit data):


	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Operating expenses:
Lease operating	$	56,426	$	48,578	$	101,904	$	98,333
Production and ad valorem taxes		21,819		21,145		42,296		39,637
Depreciation, depletion and amortization		126,982		126,803		245,129		254,705
Impairment of oil and gas properties		312,070		11,061		312,070		80,330
Asset retirement obligation accretion		1,207		1,164		2,405		2,325
Related party management fee		5,513		5,250		11,025		10,500
General and administrative		38,235		34,264		79,214		64,935

Total operating expenses	$	562,252	$	248,265	$	794,043	$	550,765


	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Average cost per unit of combined production ($ per Mcfe):
Production costs:
Lease operating expense	$	1.14	$	0.90	$	1.05	$	0.92
Production and ad valorem taxes		0.44		0.39		0.44		0.37

Total production cost per unit	$	1.58	$	1.29	$	1.49	$	1.29

Lease operating expense, net of stock compensation	$	1.12	$	0.88	$	1.01	$	0.90
Depreciation, depletion and amortization	$	2.57	$	2.34	$	2.53	$	2.37
General and administrative expenses	$	0.77	$	0.63	$	0.82	$	0.61
General and administrative expenses, net of stock compensation	$	0.58	$	0.54	$	0.62	$	0.52

Lease operating expenses (“LOE”). LOE increased $7.8 million and $3.6 million for the three and six months ended June 30, 2014, respectively. On a per unit basis, LOE per Mcfe increased by $0.24 and $0.13 for the three and six month periods ended June 30, 2014, respectively, as compared to the corresponding prior year periods. In the second quarter of 2014, we adjusted our estimated accrual rate to reflect increased operating costs we are experiencing as we continue to shift our focus to oil and liquids rich gas plays, which increased LOE per Mcfe by $0.15 and $0.08 for the three and six month periods ended June 30, 2014, respectively. For the remainder of the year, we forecast our LOE on a per unit basis to approximate $1.00 to $1.05 per Mcfe due to our continued emphasis on oil and liquids rich gas plays.

Production and ad valorem taxes. Production and ad valorem taxes increased $0.7 million and $2.7 million for the three and six months ended June 30, 2014, respectively. The increase in expense for the six months ended June 30, 2014 results from a reduction of ad valorem tax expense recorded in the first quarter of 2013 to reflect actual property tax assessments that were less than previous estimates. On a per unit basis, for the three and six months ended June 30, 2014, production and ad valorem taxes increased by 13.0% and 17.9% per Mcfe, respectively, as compared to prior year periods as a result of higher realized pricing.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense decreased $9.6 million for the six months ended June 30, 2014 primarily as a result of lower overall production as compared to prior year periods. On a per unit basis, depreciation, depletion and amortization expense increased by 9.6% and 6.4% per Mcfe for the three and six months ended June 30, 2014, respectively, as a result of lower total proved reserve volumes as compared to prior year periods.

Impairment of oil and gas properties. We recorded a pre-tax impairment expense related to our oil and gas properties for the three and six months ended June 30, 2014 and 2013 of $312.1 million and $11.1 million, respectively, and $312.1 million and $80.3 million, respectively, as a result of our full-cost ceiling test. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of costs associated with our oil and gas properties that can be capitalized in our condensed consolidated balance sheets. Contributing to the impairment expense for the three and six months ended June 30, 2014 were impairments of our unproved properties of approximately $168.8 million.

Related party management fee. We have a consulting agreement with affiliates of our initial equity investors pursuant to which we receive management services and incur a quarterly management fee to our private equity sponsors. In accordance with the consulting agreement, the management fee increases 5% on an annual basis. The related party management fee increased $0.3 million and $0.5 million for the three and six months ended June 30, 2014, respectively.

General and administrative expenses. General and administrative expenses increased $4.0 million and $14.3 million for the three and six months ended June 30, 2014, respectively, as compared to prior year periods. For the three months ended June 30, 2014, increased costs associated with long-term cash incentive accruals of $3.2 million as well as $0.9 million in additional non-cash compensation expense for restricted stock issued at the end of the first quarter of 2014 led to higher quarterly general and administrative costs. In addition to these cost increases for the three months ended June 30, 2014, general and administrative expenses for the six months ended June 30, 2014 were also impacted by approximately $5.1 million non-cash expense due to the repricing of the majority of outstanding options in the first quarter of 2014. Also contributing to the increase for the six months ended June 30, 2014 was an increase of approximately $2.2 million in expense related to employer contributions for 401(k) matching in the first quarter of 2014 and higher compensation expenses of approximately $1.0 million related to the repurchase of 390,000 shares of puttable common stock at a price above fair market value also in the first quarter of 2014.

Interest expense. Interest expense was $21.4 million and $41.9 million for the three and six months ended June 30, 2014, respectively. Interest expense associated with our RBL Revolver, Senior Notes, Second Lien Term Loan, cumulative preferred stock, and amortization of loan commitment and other fees is capitalized based on the cost of certain unproved oil and gas properties excluded from amortization where we have ongoing exploration or development activities. We capitalized interest costs to unproved oil and gas properties of $64.7 million and $84.9 million during the three months ended June 30, 2014 and 2013, respectively, and $128.3 million and $166.4 million during the six months ended June 30, 2014 and 2013, respectively. Our interest expense for each period, if any, represents the amount by which our total interest cost incurred exceeds the amount of interest we capitalize. Total interest cost for the three and six months ended June 30, 2014 was $86.1 million and $170.3 million, respectively, compared with $84.9 million and $166.4 million for the three and six months ended June 30, 2013, respectively. The increase in total interest cost was the result of additional interest on the Senior Notes, which we began to incur in May 2013 pursuant to the terms of the registration rights agreement relating to the Senior Notes. For additional information, see “Senior Notes” under Note 8 to the Condensed Consolidated Financial Statements.

Income tax provision. Income tax benefit was $115.1 million and $115.6 million for the three and six months ended June 30, 2014, respectively, as compared to an income tax provision of $46.0 million and $13.6 million for the three and six months ended June 30, 2013, respectively. The change in the income tax provision (benefit) for the three and six months ended June 30, 2014 is due to the difference in pre-tax income (loss) between the periods. The effective income tax rate for the three months ended June 30, 2014 and 2013 was approximately 35.7% and 35.7%, respectively, and 35.6% and 35.5% for the six months ended June 30, 2014 and 2013, respectively. Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax assets will be realized. The amount of the deferred tax assets considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.

Liquidity and Capital Resources

The following table summarizes factors affecting our liquidity at June 30, 2014 and December 31, 2013 (in thousands):


	At June 30, 2014		At December 31, 2013
Cash and cash equivalents	$	13,310	$	727
Total debt	$	3,750,000	$	3,554,000
Shareholders’ equity	$	1,320,767	$	1,512,742
Available borrowing capacity under RBL Revolver	$	498,219	$	1,473,819

Cash and Cash Equivalents

All cash is denominated in U.S. dollars and, at times, is invested in highly liquid, investment-grade securities with maturities of three months or less at the time of purchase.

Debt

At June 30, 2014, total outstanding debt was approximately $3.8 billion, which excludes approximately $196.9 million of our cumulative preferred stock. Our total debt consists of three separate financing arrangements: the RBL Revolver, which at June 30, 2014, had a total borrowing capacity of approximately $1.0 billion and outstanding borrowings of $500.0 million; our Senior Notes, which were issued in 2012 for an aggregate principal amount of $2.25 billion; and our Second Lien Term Loan, under which we have borrowed an aggregate principal amount of $1.0 billion. As discussed below, we amended the credit agreement governing the RBL Revolver in May 2014, which reduced our borrowing base from approximately $1.8 billion to $1.0 billion.

In May 2014, we amended the credit agreement governing the RBL Revolver to, among other things, modify the financial performance covenant to provide that we shall maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 1.5 to 1.0 until the end of 2015. Beginning with the first quarter of 2016, we will be required to maintain a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0. Prior to the amendment, the financial performance covenant required us to maintain a ratio of consolidated total debt to consolidated EBITDA of not more than 5.5 to 1.0 during 2014, with a step down to 5.0 to 1.0 beginning with the first quarter of 2015 and a final step down to 4.5 to 1.0 beginning with the first quarter 2016. In addition, the amendment modified the credit agreement governing the RBL Revolver by permitting us to incur an additional $500.0 million of second lien debt without a further related reduction to the borrowing base, subject to certain limitations and conditions. The modification of the financial performance covenant had the effect of increasing our liquidity despite the reduction to our borrowing base.

As described above, the financial performance covenant in the credit agreement governing the RBL Revolver requires us to operate within established financial ratios. This covenant could restrict our ability to engage in certain actions, including by potentially limiting our ability to sell assets or make future borrowings under the RBL Revolver or incur other additional indebtedness. Forecasting our compliance with the financial covenant in future periods is inherently uncertain. Factors that could impact our future compliance with the financial performance covenant include future realized prices for the sales of oil, natural gas and natural gas liquids, estimated future production, returns generated by our capital program, future interest costs, future operating costs, proceeds received from future asset sales, and future equity contributions, among others.

Contractual Obligations

Our contractual obligations include long-term debt, interest expense on debt, drilling commitments, preferred shares subject to mandatory redemption, other operating lease obligations and marketing commitments. There were no material changes in our contractual obligations at June 30, 2014 as compared to December 31, 2013.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity and capital resource positions or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments as described in Note 12 to the Condensed Consolidated Financial Statements.

Capital Commitments

Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations, including debt service obligations, and our working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, borrowings under our RBL Revolver or alternative financing sources and proceeds from the disposition of assets.

Our cash flows are significantly impacted by the price we receive for our oil, natural gas and NGL production. A decrease in commodity prices negatively impacts our revenues, earnings and cash flows and therefore could impact our liquidity. Additionally, sustaining our cash flows is dependent upon replacing our reserves depleted through production and containing the costs necessary to produce those reserves. We must expend cash to fund our capital investments, which is necessary to offset the inherent production declines. Our ability to grow, or even maintain reserves and related production is dependent on the success of our exploration and development drilling activities.

We have moderately reduced our planned capital spending in 2014 to focus our drilling and completion activities in areas that we believe have a higher probability of achieving acceptable returns for our invested capital. As a result, we expect our actual drilling and completion expenditures during 2014 to be less than our initially budgeted amount and less than amounts expended in prior years on drilling and completion activities. We believe a measured approach to our capital funding of development activities will allow us to better manage our debt service obligations while at the same time achieve returns that provide for future growth opportunities in the core areas in which we operate.

Considering the amendment of the RBL Revolver discussed above, our reduction in planned capital spending for 2014, anticipated operating results and future cash flows and the potential sources of financing that we have available, we do not anticipate any significant liquidity constraints over the next twelve months. However, to the extent operating cash flows or access to and cost of financing sources are materially different than expected, future liquidity may be adversely affected.

Capital Expenditures

Total capital expenditures, including capitalized direct internal costs and interest paid, were approximately $494.2 million for the six months ended June 30, 2014. Substantially all of our expenditures, excluding capitalized direct internal costs and interest paid, relate to the acquisition and development of our oil and gas properties with the remaining expenditures relating primarily to the acquisition and construction of facilities used to support our operational requirements. Our capital expenditures include interest and direct internal costs that are capitalized and increase the basis of our oil and gas properties.

The following table summarizes our capital budget as approved by our board of directors for the year ended December 31, 2014, which excludes capitalized direct internal costs and interest paid (in thousands):


	2014 Capital Budget
Drilling and completion:
West Division	$	336,314
East Division		334,469

Total drilling and completion		670,783

Leasehold, geological and geophysical		14,642
Related field facilities, corporate and other		43,470

Total capital budget, excluding capitalized direct internal costs and interest paid	$	728,895

The following table sets forth information regarding capital expenditures for the six months ended June 30, 2014 (in thousands):


Drilling and completion	$	321,205
Tubular oil and gas equipment, prepaid drilling costs and other		9,053

Total drilling and completion		330,258
Leasehold, geological and geophysical		3,161
Related field facilities, corporate and other		9,275

Total		342,694
Capitalized interest paid		135,578
Capitalized direct internal costs		15,878

Total capital expenditures	$	494,150

We primarily fund our capital expenditures with our cash flows generated by operations, borrowings under our RBL Revolver, or other alternative financing sources. The actual amount and timing of our expenditures may differ materially from our estimates as a result of actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions, among other factors. In addition, under certain circumstances we will consider increasing or reallocating our capital spending plans. As discussed above, we have moderately reduced our planned capital spending in 2014 to focus our drilling and completion activities in areas that we believe have a higher probability of achieving acceptable returns for our invested capital. As a result, we expect our actual drilling and completion expenditures during 2014 to be less than our initially budgeted amount.

Sources and Uses of Cash

The following table summarizes our net change in cash and cash equivalents for the periods shown (in thousands):


	Six Months Ended June 30,
	2014			2013
Operating activities	$	260,402		$	332,312
Investing activities		(440,662	)		(423,887	)
Financing activities		192,843			134,050

Net change in cash	$	12,583		$	42,475

Cash flows from operating activities. Cash flows from operating activities decreased $71.9 million for the six months ended June 30, 2014 as compared to the prior year period. The decrease in cash flows from operating activities was primarily the result of cash payments for settled derivatives of $72.7 million during the six months ended June 30, 2014 compared to cash receipts for settled derivatives of $4.0 million during the six months ended June 30, 2013. These cash payments for settled derivatives were partially offset by higher oil and gas revenues of $40.4 million compared to the six months ended June 30, 2013. Also impacting cash flows from operating activities was a decrease in the amount of capitalized cash interest, which decreased operating cash flows by $14.6 million.

Cash flows used in investing activities. Cash flows used in investing activities increased $16.8 million for the six months ended June 30, 2014 as compared to the prior year period. The increase in cash flows used in investing activities was primarily the result of a decrease in proceeds from divestitures of oil and gas properties of $54.0 million partially offset by a decrease in capital expenditures for oil and gas properties and other property and equipment of $39.2 million as compared to the six months ended June 30, 2013. We continue to moderate our capital spend as we focus our drilling on our core areas that have a higher probability of achieving acceptable returns for our invested capital. A decrease in our capitalized cash interest of $14.6 million from the prior year period also impacted our cash flows used in investing activities.

Cash flows from financing activities. Cash flows from financing activities increased $58.8 million for the six months ended June 30, 2014 as compared to the prior year period. The increase in cash flows provided by financing activities was primarily the result of an increase in net borrowings on the RBL Revolver of $61.0 million. Borrowings under the RBL Revolver are primarily utilized to fund our capital expenditures as well as for general corporate purposes.

Related Party Transactions

For a discussion of related party transactions, see Note 14 to the Condensed Consolidated Financial Statements.

Critical Accounting Policies

There were no changes in our critical accounting policies and estimates from December 31, 2013. Information regarding our critical accounting policies and estimates is included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Prospectus.

Recent Accounting Pronouncements

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil, NGL and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures.

Commodity Price Exposure

Our revenues and associated cash flows are dependent on the prices we receive for our crude oil, natural gas and NGLs, which can be volatile because of unpredictable events such as economic circumstances, weather, and political climate, among others. We periodically enter into derivative positions on a portion of our projected oil, natural gas and NGL production to manage fluctuations in cash flows resulting from changes in commodity prices. For the six months ended June 30, 2014, approximately 81% of our natural gas production, approximately 121% of our crude oil production and approximately 56% of our NGL production was subject to financial derivatives. All of our market risk sensitive instruments were entered into for risk mitigation purposes, rather than for speculative trading.

At June 30, 2014, we had open natural gas derivatives, crude oil and NGL derivatives in a liability position with a combined fair value of $83.4 million. A ten percent increase in natural gas, crude oil and NGL prices would increase the liability position by approximately $52.9 million. See Note 6 to our Condensed Consolidated Financial Statements for notional volumes and terms associated with the Company’s derivative contracts.

Interest Rate Risk

As part of our RBL Revolver and Second Lien Term Loan, we have debt which bears interest at a floating rate. For the six months ended June 30, 2014, the weighted average interest rates on our RBL Revolver and Second Lien Term Loan were 2.0% and 5.0%, respectively. Assuming all revolving loans are fully drawn under the RBL Revolver, each quarter point increase in interest rates would result in a $5.0 million increase in annual interest cost, before capitalization.

Exchange Rate Risk

All of our transactions are denominated in U.S. dollars, and as a result, we do not currently have exposure to currency exchange-rate risks.

Credit Risk

Cash and cash equivalents are not insured above FDIC insurance limits, causing us to be subject to risk. Accounts receivable are primarily due from other companies within the oil and natural gas industry. A portion of the receivables are due from major oil and natural gas purchasers with which we have large natural offsets between revenues and joint interest billings. We do not generally require collateral related to these receivables; however, cash prepayments and letters of credit are requested for accounts with indicated credit risk. All of our derivative exposure is with banks that are lenders under our RBL Revolver or their respective affiliates.

ITEM 4. CONTROLS AND PROCEDURES

Material Weaknesses in Internal Control over Financial Reporting and Remediation Efforts. As previously disclosed in the Prospectus, we identified material weaknesses in our internal control over financial reporting in connection with the preparation of our financial statements for the year ended December 31, 2013 related to the valuation and disclosure of our estimated proved reserves and the preparation of the cash flow statement. The material weaknesses relating to the valuation and disclosure of our estimated proved reserves were due to ineffective controls associated with the review of certain underlying data and assumptions used in the reserve valuation process.

Upon identification of the material weaknesses, we began remediation efforts to improve our internal controls. As it relates to the material weaknesses associated with the valuation and disclosure of our estimated proved reserves, our remediation efforts are still in progress. We are implementing new processes and control procedures with respect to reserve estimations and have hired additional internal reservoir engineers, including a new Director of Reserves and Technology, who joined the Company during the three months ended June 30, 2014. The implementation of these changes to our control environment is ongoing, and our remediation efforts have not yet been subject to year-end testing.

Management’s Evaluation of Disclosure Controls and Procedures. As required by Rule 15d-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2014. Our disclosure controls and procedures are controls and procedures that we have designed to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to the financial statement preparation and presentation. In light of the material weaknesses described above, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of June 30, 2014. Notwithstanding such material weaknesses, management concluded that the financial statements and other financial information included in this report present fairly, in all material respects, the financial condition, results of operations and cash flows for all periods presented.

Changes in Internal Control over Financial Reporting. We began transacting with our newly implemented enterprise resource planning system in January 2014, which resulted in conforming adjustments to certain internal control processes throughout 2014. Except for these changes and the remediation efforts described above, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we are party to various legal proceedings arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of pending legal actions will not have a material adverse effect on our business, results of operations and financial condition. For additional information, see the discussion under “Litigation and Contingencies” in Note 12 to the Condensed Consolidated Financial Statements.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in the section entitled “Risk Factors” included in the Prospectus. Those risk factors, in addition to the other information set forth in this report, could materially and adversely affect our business, results of operations and financial condition. Such risks and uncertainties are not the only risks and uncertainties that we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also materially and adversely affect our business, results of operations and financial condition.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On April 7, 2014, we awarded a total of 1,000,000 shares of restricted stock and 900,000 stock options having an exercise price of $2.50 per share, and, on May 15, 2014, we made a subsequent award of 500,000 stock options having an exercise price of $2.50 per share. These awards were made to certain employees of the Company pursuant to the 2011 Plan. The awards were not registered under the Securities Act in reliance upon Section 4(a)(2) of the Securities Act, as transactions not involving a public offering, and Rule 12h-1 under the Exchange Act. For additional information regarding equity incentive awards made under the 2011 Plan, see Note 10 to the Condensed Consolidated Financial Statements.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC

File No.

Exhibit

Filing Date

Filed
Herewith*

4.1

Amendment to the First Supplemental Indenture, dated as of July 21, 2014, among Samson Resources Corporation, Samson Investment Company and Wells Fargo Bank, National Association, as trustee.

S-4/A

333-186686

4.4

7/21/2014

—

10.1

Fourth Amendment Agreement to Credit Agreement among Samson Investment Company, as the Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the several Lenders party thereto, dated as of May 9, 2014.

S-4/A

333-186686

10.5

5/13/2014

—

10.2

Samson Resources Corporation Form of Restricted Stock Award Agreement (2014).

S-4/A

333-186686

10.42

6/30/2014

—

31.1

Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated August 14, 2014, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated August 14, 2014, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated August 14, 2014, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated August 14, 2014, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Schema Document.

101.CAL

XBRL Calculation Linkbase Document.

101.LAB

XBRL Label Linkbase Document.

101.PRE

XBRL Presentation Linkbase Document.

101.DEF

XBRL Definition Linkbase Document.

*	Or furnished, in the case of Exhibits 32.1, 32.2 and the XBRL exhibits.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in Tulsa, Oklahoma, on August 14, 2014.


SAMSON RESOURCES CORPORATION

By:		/s/ Philip W. Cook
		Philip W. Cook
		Executive Vice President and Chief Financial Officer
		(Authorized Signatory and Principal Financial Officer)

INDEX TO EXHIBITS

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC

File No.

Exhibit

Filing Date

Filed
Herewith*

4.1

Amendment to the First Supplemental Indenture, dated as of July 21, 2014, among Samson Resources Corporation, Samson Investment Company and Wells Fargo Bank, National Association, as trustee.

S-4/A

333-186686

4.4

7/21/2014

—

10.1

S-4/A

333-186686

10.5

5/13/2014

—

10.2

Samson Resources Corporation Form of Restricted Stock Award Agreement (2014).

S-4/A

333-186686

10.42

6/30/2014

—

31.1

Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated August 14, 2014, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated August 14, 2014, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated August 14, 2014, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated August 14, 2014, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Schema Document.

101.CAL

XBRL Calculation Linkbase Document.

101.LAB

XBRL Label Linkbase Document.

101.PRE

XBRL Presentation Linkbase Document.

101.DEF

XBRL Definition Linkbase Document.

*	Or furnished, in the case of Exhibits 32.1, 32.2 and the XBRL exhibits.

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company