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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 March 31, 2015

 

¨	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  x    No  ¨

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.

 

Large accelerated filer		¨		Accelerated filer		¨
Non-accelerated filer		x  (Do not check if a smaller reporting company)		Smaller reporting company		¨

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 May 15, 2015, Samson Resources Corporation had 842,192,180 shares of common stock outstanding.

 

 

 

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SAMSON RESOURCES CORPORATION

TABLE OF CONTENTS

 

				Page Number
Part I. FINANCIAL INFORMATION					3
Item 1.		Financial Statements (Unaudited)			3
		Condensed Consolidated Balance Sheets at March 31, 2015 and December 31, 2014			3
		Condensed Consolidated Statements of Loss and Comprehensive Loss for the Three Months Ended March  31, 2015 and 2014			4
		Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014			5
		Notes to Condensed Consolidated Financial Statements			6
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			30
Item 3.		Quantitative and Qualitative Disclosures about Market Risk			45
Item 4.		Controls and Procedures			46
Part II. OTHER INFORMATION					47
Item 1.		Legal Proceedings			47
Item 1A.		Risk Factors			47
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			47
Item 3.		Defaults Upon Senior Securities			47
Item 4.		Mine Safety Disclosures			47
Item 5.		Other Information			47
Item 6.		Exhibits			48
Signatures					50
Index to Exhibits					51
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)

 

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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 (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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, liquidity, operational and financial performance, compliance with debt covenants, 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) our substantial indebtedness; (ii) our ability to refinance, restructure or amend our indebtedness or otherwise improve our capital structure and liquidity; (iii) our ability to generate or obtain sufficient cash to service our indebtedness and other obligations; (iv) fluctuations in oil and natural gas prices; (v) restrictions contained in our debt agreements; (vi) the uncertainty inherent in estimating our reserves, future net revenues and discounted future cash flows; (vii) the timing and amount of future production of oil and natural gas; (viii) cash flow and changes in the availability and cost of capital; (ix) environmental, drilling and other operating risks, including liability claims as a result of our oil and natural gas operations; (x) proved and unproved drilling locations and future drilling plans; (xi) the effects of existing and future laws and governmental regulations, including environmental, hydraulic fracturing and climate change regulation; (xii) our ability to make acquisitions and divestitures on favorable terms or at all; and (xiii) any of the risk factors and other cautionary statements described in our 2014 Annual Report on Form 10-K or under Part II, Item 1A—“Risk Factors” in this report or in any other report, registration statement or other document that we may file from time to time with the Securities and Exchange Commission (the “SEC”).

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.

 

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)

SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share and per share data)

 

		March 31, 2015				December 31, 2014
Assets
Current assets:
Cash and cash equivalents		$	194,056			$	23,826
Accounts receivable, net			147,592				173,524
Prepaid expenses and other			6,879				11,488
Derivative assets			117,273				127,743
Total current assets			465,800				336,581
Property, plant and equipment, net:
Oil and gas properties, full cost method:
Proved properties			2,103,821				2,553,102
Unproved properties not being amortized			2,070,274				2,269,521
Other property and equipment			287,744				291,761
Total property, plant and equipment, net			4,461,839				5,114,384
Derivative assets			45,352				29,734
Deferred charges			79,510				100,673
Other noncurrent assets			32,640				26,940
Total assets		$	5,085,141			$	5,608,312
Liabilities and Equity
Current liabilities:
Accounts payable		$	96,237			$	20,091
Oil and gas revenues held for distribution			72,417				92,866
Accrued and other current liabilities			213,680				324,630
Derivative liabilities			3,124				5,790
Current deferred income taxes			22,510				18,500
Debt classified as current (Note 10)			4,197,000				3,905,000
Total current liabilities			4,604,968				4,366,877
Deferred credits and other long-term liabilities			89,890				99,265
Deferred income tax liabilities			465,861				746,837
Cumulative preferred stock subject to mandatory redemption ($0.10 par value, 180,000 shares authorized, issued and outstanding, recorded at redemption value)			206,865				202,808
Commitments and contingencies (Note 14)
Puttable common stock ($0.01 par value, 200,000 shares issued and outstanding at March 31, 2015 and December 31, 2014)			1,000				1,000
Shareholders’ equity (deficit):
Common stock ($0.01 par value, 2,000,000,000 shares authorized, with 843,500,000 and 845,400,000 shares issued and outstanding at March 31, 2015 and December 31, 2014)			8,290				8,290
Additional paid-in capital			4,293,514				4,268,415
Accumulated deficit			(4,619,982	)			(4,129,651	)
Accumulated other comprehensive income			34,735				44,471
Total shareholders’ equity (deficit)			(283,443	)			191,525
Total liabilities and shareholders’ equity (deficit)		$	5,085,141			$	5,608,312

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

 

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SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF LOSS AND

COMPREHENSIVE LOSS

(Unaudited)

(In thousands)

 

		Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
Revenues:
Natural gas and natural gas liquids sales		$	95,157			$	196,131
Crude oil sales			52,633				112,126
Commodity derivatives, net			58,386				(57,329	)
Total revenues			206,176				250,928
Operating expenses:
Lease operating			54,053				45,478
Production and ad valorem taxes			11,993				20,477
Depreciation, depletion, and amortization			103,762				118,146
Impairment of oil and gas properties			629,517				—
Asset retirement obligation accretion			1,610				1,198
Restructuring charges			34,566				—
Related party management fee			5,788				5,512
General and administrative			58,858				40,980
Total operating expenses			900,147				231,791
Operating income (loss)			(693,971	)			19,137
Interest expense, net			(64,127	)			(20,476	)
Other expense, net			(3,792	)			(132	)
Loss before income taxes			(761,890	)			(1,471	)
Income tax benefit			(271,559	)			(449	)
Net loss		$	(490,331	)		$	(1,022	)
Other comprehensive income (loss):
Unrealized loss from cash flow hedges, net of tax of $(4,019) in 2014			—				(7,235	)
Reclassification for settled cash flow hedges, net of tax of $(5,407) and $768, in 2015 and 2014, respectively			(9,736	)			1,381
Total other comprehensive loss, net of tax			(9,736	)			(5,854	)
Total comprehensive loss		$	(500,067	)		$	(6,876	)

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

 

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SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

 

		Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
Operating activities:
Net loss		$	(490,331	)		$	(1,022	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Commodity derivatives, net			(58,386	)			57,329
Cash settlements of derivative instruments, net			48,315				(37,692	)
Stock based compensation expense			22,868				13,237
Depreciation, depletion and amortization			103,762				118,146
Loss on sale of other property and equipment			3,784				—
Impairment of oil and gas properties			629,517				—
Asset retirement obligation accretion			1,610				1,198
Accretion of preferred stock not capitalized			2,373				600
Loss on modification of debt			15,122				—
Amortization of debt cost not capitalized			3,534				1,553
Benefit for deferred income taxes			(271,559	)			(449	)
Other noncash items			—				162
Change in operating assets and liabilities:
Accounts receivable			36,183				(50,174	)
Prepaid expenses and other			2,109				4,253
Accounts payable			19,262				(16,340	)
Oil and gas revenues held for distribution			(20,449	)			8,958
Accrued and other current liabilities			(21,375	)			(3,801	)
Deferred credits and other long-term liabilities			(5,867	)			7,245
Net cash provided by operating activities			20,472				103,203
Investing activities:
Capital expenditures—oil and gas properties			(195,060	)			(263,566	)
Capital expenditures—other property and equipment			(7,794	)			(5,035	)
Proceeds from divestitures—oil and gas properties			60,112				5,502
Proceeds from divestitures—other property and equipment			500				3
Net cash used in investing activities			(142,242	)			(263,096	)
Financing activities:
Proceeds from revolver			338,000				172,000
Repayment of revolver			(46,000	)			(10,000	)
Repurchase of stock			—				(2,190	)
Net cash provided by financing activities			292,000				159,810
Net change in cash			170,230				(83	)
Cash and cash equivalents at beginning of period			23,826				727
Cash and cash equivalents at end of period		$	194,056			$	644

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

 

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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 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, 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 condensed consolidated balance sheet at December 31, 2014 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 March 31, 2015 and our results of operations and cash flows for the three month periods ended March 31, 2015 and 2014. All adjustments are of a normal recurring nature. The results of interim periods are not necessarily indicative of annual results.

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 audited consolidated financial statements and notes included in our 2014 Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (“SEC”).

Industry conditions, liquidity, management’s plans, and going concern

We have historically funded our operations with operating cash flow, borrowings under our various credit facilities, and asset sales. Our most significant cash outlays relate to our capital program, current period operating expenses, payments under various long-term incentive plans, and our debt service obligations.

The market price for oil, natural gas and NGLs decreased significantly during the fourth quarter of 2014 with continued weakness into 2015. The decrease in the market price for our production directly reduces our operating cash flow and indirectly impacts our other sources of potential liquidity described above. Lower market prices for our production may result in lower borrowing capacity under our revolving credit facility or higher borrowing costs from other potential sources of debt financing as our borrowing capacity and borrowing costs are generally related to the value of our estimated proved reserves. The weakness in product pricing may also impact our ability to negotiate asset sales at acceptable prices.

In addition, declining industry conditions and company performance reduces the likelihood that we comply with certain restrictive covenants contained in our credit facilities. Our restrictive covenants contained in our various credit facilities, along with the consequences of potentially not complying with those restrictive covenants are described in Note 10. On March 18, 2015, we executed an amendment to our revolving credit facility to change the financial performance covenant beginning with the first quarter of 2015 through and including the third quarter of 2015 from the existing ratio of first lien debt to consolidated EBITDA of 1.5 to 1.0 to 2.75 to 1.0. Beginning October 1, 2015, the financial performance covenant reverts back to a ratio of first lien debt to consolidated EBITDA of not more than 1.5 to 1.0 for the remainder of 2015 and a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 beginning with the first quarter of 2016. In addition, the March 18, 2015 amendment established a liquidity covenant which requires us to maintain minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due in 2020 (the “Senior Notes”) and the Second Lien Term Loan. Unless the financial performance and/or the liquidity covenants are amended further or we are successful in implementing one of the strategic alternatives discussed below, we do not expect to remain in compliance with all of our restrictive covenants throughout 2015 or early 2016. The amendment also waived certain restrictions related to the form and content of our auditor’s report for the year ended December 31, 2014 and increased the collateral coverage minimum (as defined in the credit agreement) to at least 95% of the discounted present value of our restricted subsidiaries proved reserves.

 

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Collectively, the negative impacts to our liquidity resulting from declining industry conditions and increased uncertainty regarding our ability to comply with restrictive covenants contained in our credit facilities raises substantial doubt about our ability to continue as a going concern. The condensed consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern. Our long-term debt with maturities summarized in Note 10 is reflected as a current liability in our condensed consolidated balance sheets. The classification as a current obligation is based on the uncertainty regarding our ability to comply with certain restrictive covenants contained in our credit agreements during 2015.

We have begun implementing plans designed to improve our liquidity. We have reduced our 2015 capital budget to approximately $156.5 million and have taken steps to reduce long-term recurring operating expenses. We are continuing our efforts to sell certain non-core assets. In March 2015, we closed a transaction to sell certain oil and gas properties in the Arkoma basin for approximately $48.0 million.

Even if we are successful at reducing our costs and increasing our liquidity through asset sales, we do not expect to have sufficient liquidity to satisfy our debt service obligations, meet other financial obligations, and comply with restrictive covenants contained in our various credit facilities. We have engaged advisors to assist with the evaluation of our options to address our liquidity position and strategic alternatives. The strategic alternatives may include, but not be limited to, seeking a restructuring, amendment or refinancing of our outstanding debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that we will be able to successfully restructure our indebtedness, improve our liquidity position, complete any strategic transactions or comply with debt covenant requirements throughout 2015 or beyond.

Significant Accounting Policies

As of March 31, 2015, there were no changes in significant accounting policies from those described in the December 31, 2014 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, and the reported amounts of revenues and expenses. Estimates and assumptions that, in the opinion of management, are significant include oil and natural gas reserves and future development costs of proved and undeveloped reserves used to compute depletion expense and the full cost ceiling limitation, allocations of value from unproved properties to proved properties when proved reserves are established or wells are completed, pricing used to calculate the full cost ceiling limitation, asset retirement obligations, fair value measurements used in the preparation of our consolidated financial statements (such as derivatives and employee stock based compensation), impairments of unproved property, capitalized interest and internal costs, assumptions used to account for loss contingencies, 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 will differ from the estimates used in the preparation of our consolidated financial statements.

Recent Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-03 “Interest-Imputation of Interest.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years for public entities. Early adoption is permitted. We are evaluating the impact of the new standard, which we expect to adopt on January 1, 2016.

In August 2014, the FASB issued ASU 2014-15 “Presentation of Financial Statements—Going Concern.” ASU 2014-15 provides guidance regarding management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for our annual period ending after December 15, 2016, and for all annual and interim periods thereafter. Early application is permitted. We have not determined when we will adopt ASU 2014-15 or the impact the new standard will have on our consolidated financial statements. Upon adoption, we will be required to consider whether there are adverse conditions or events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued. Adverse conditions or events would include, but not be limited to, negative financial trends, a need to restructure outstanding debt to avoid default, and industry developments.

 

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In May 2014, the 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. In April 2015, the FASB voted to propose to defer the effective date by one year. Early adoption is permitted. We are currently evaluating the potential impact of ASU 2014-09 on our consolidated financial statements.

 

Note 2.

Divestitures

In March 2015, we closed a transaction to sell certain oil and gas properties in the Arkoma basin for approximately $48.0 million. The net sales proceeds have been reflected as a reduction of proved oil and gas properties, with no gain or loss recognized.

 

Note 3.

Property, Plant and Equipment

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

 

		March 31, 2015				December 31, 2014
Oil and gas properties:
Proved properties		$	10,845,716			$	10,569,969
Unproved properties excluded from amortization			2,035,552				2,164,708
Uncompleted capital project costs excluded from amortization			34,722				104,813
Accumulated depletion			(8,741,895	)			(8,016,867	)
Net oil and gas properties			4,174,095				4,822,623
Other property and equipment			383,977				384,161
Accumulated depreciation			(96,233	)			(92,400	)
Net other property and equipment			287,744				291,761
Property, plant and equipment, net of accumulated depletion and depreciation		$	4,461,839			$	5,114,384

Oil and Gas Properties

We utilize the full cost method of accounting for oil and gas properties. We recorded approximately $98.9 million and $62.8 million of impairment of unproved properties during the three months ended March 31, 2015 and 2014, respectively, 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 properties and are excluded from amortization. The following table summarizes capitalized internal costs and capitalized interest costs for the three months ended March 31, 2015 and 2014 (in thousands):

 

		Three Months Ended March 31,
		2015				2014
Capitalized internal costs, excluding stock compensation		$	6,504			$	7,948
Capitalized stock compensation			1,339				2,623
Capitalized interest costs			34,772				63,645
		$	42,615			$	74,216

During the three months ended March 31, 2015, the net capitalized cost of oil and gas properties subject to depletion exceeded the ceiling amount during the quarterly full cost ceiling tests. As a result, we recorded impairment expense associated with our oil and gas properties in the amount of $629.5 million for the three months ended March 31, 2015.

 

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Note 4.

Other Noncurrent Assets

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

 

		March 31, 2015				December 31, 2014
Tubular and oil and gas equipment		$	22,437			$	18,428
Prepaid drilling costs			5,683				4,272
Other			4,520				4,240
		$	32,640			$	26,940

 

Note 5.

Accrued and Other Current Liabilities

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

 

		March 31, 2015				December 31, 2014
Accrued interest		$	28,336			$	84,153
Accrued capital and other expenditures			70,000				111,099
Accrued compensation and benefits			27,816				59,101
Accrued restructuring charges			23,265				—
Production and ad valorem taxes			30,776				33,549
Book cash overdrafts			4,485				112
Asset retirement obligation (current portion)			2,250				3,044
Advance payments from and payables to partners			14,075				26,658
Other			12,677				6,914
		$	213,680			$	324,630

 

Note 6.

Deferred Credits and Other Long-Term Liabilities

The following table presents the components of deferred credits and other long-term liabilities (in thousands):

 

		March 31, 2015				December 31, 2014
Asset retirement obligation		$	67,138			$	72,668
Gas balancing liability			11,165				14,553
Other long-term liabilities			11,587				12,044
		$	89,890			$	99,265

 

Note 7.

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):

 

		Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
Asset retirement obligations as of beginning of period		$	75,712			$	60,408
Liabilities incurred			373				259
Liabilities settled			(88	)			(895	)
Disposition of wells			(8,213	)			(270	)
Accretion expense			1,610				1,198
Revisions			(6	)			653
Asset retirement obligations as of end of period		$	69,388			$	61,353

 

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Note 8.

Derivative Financial Instruments

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 tables set forth our net open derivative positions as of March 31, 2015:

 

		Natural Gas Fixed Price Swaps								Crude Oil Fixed Price Swaps
Period		Volume (MMBtu)				Weighted Average Price ($/MMBtu)				Volume (MBBls)				Average Price ($/BBl)
Remainder of 2015			45,710,200			$	4.04				963			$	90.91
2016			48,005,800			$	4.04				—			$	—
2017			14,600,000			$	3.92				—			$	—

 

		Natural Gas Collars
Period		Volume (MMBtu)				Weighted Average Floor/Ceiling Price ($/MMBtu)
Remainder of 2015			5,500,000			$	4.00/5.13
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 2015			3,869			$	0.27				2,339			$	1.09				1,184			$	2.03				1,271			$	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.

 

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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 condensed consolidated balance sheets.

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

 

		March 31, 2015
		Gross Assets				Gross Liabilities				Netting (a)				Net Amount Presented in Consolidated Balance Sheets
Derivatives not designated as cash flow hedges:
Current derivative assets		$	129,079			$	—			$	(11,806	)		$	117,273
Noncurrent derivative assets			45,352				—				—				45,352
Current derivative liabilities			—				(14,930	)			11,806				(3,124	)
Total derivatives not designated as cash flow hedges		$	174,431			$	(14,930	)		$	—			$	159,501
		December 31, 2014
		Gross Assets				Gross Liabilities				Netting (a)				Net Amount Presented in Consolidated Balance Sheets
Derivatives designated as cash flow hedges:
Current derivative assets		$	51,905			$	—			$	—			$	51,905
Noncurrent derivative assets			21,499				—				(78	)			21,421
Current derivative liabilities			—				—				—				—
Noncurrent derivative liabilities			—				(78	)			78				—
Total derivatives designated as cash flow hedges			73,404				(78	)			—				73,326
Derivatives not designated as cash flow hedges:
Current derivative assets			97,406				—				(21,568	)			75,838
Noncurrent derivative assets			8,313				—				—				8,313
Current derivative liabilities			—				(27,358	)			21,568				(5,790	)
Total derivatives not designated as cash flow hedges			105,719				(27,358	)			—				78,361
Total derivatives		$	179,123			$	(27,436	)		$	—			$	151,687

 

(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.

 

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Cash Flow Hedges

Prior to January 1, 2015, we had 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 were recorded through other comprehensive income (loss) and did not impact net income (loss) until the underlying physical transaction settled. Once the underlying physical transaction settled, the cash settlement gain or loss on the related cash flow hedge was recorded as commodity derivatives, net in our condensed consolidated statements of loss and comprehensive loss. Any change in the fair value of cash flow hedges resulting from ineffectiveness was recognized in current earnings in commodity derivatives, net.

Effective January 1, 2015, we discontinued hedge accounting on all of our existing cash flow hedges and began accounting for these derivatives using the mark-to-market accounting method. At the time of hedge de-designation, the net gains and losses deferred in accumulated other comprehensive income associated with these contracts remain and will be reclassified to earnings in the periods the original forecasted hedged transaction occurs, unless the forecasted transaction becomes not probable of occurring, which will result in an immediate reclassification to earnings. For the remainder of 2015 and for the years ending December 31, 2016 and 2017 the Company expects to reclassify deferred gains on discontinued cash flow hedges of $31.1 million, $17.4 million and $5.5 million, respectively, to oil and gas revenues. Accumulated other comprehensive income at March 31, 2015 included $34.7 million, net of tax, related to these cash flow hedges that will be recognized over the next 2.75 years as the forecasted transactions affect earnings. We will recognize $23.3 million in gains, net of income tax, over the next twelve months. The following table presents separately the pretax cash settlements and unrealized gains and losses included in the condensed consolidated statements of loss and comprehensive loss for the periods presented (in thousands):

 

		Three Months Ended March 31,
		2015				2014				Classification
Net gain (loss) recognized in other comprehensive income (loss) due to the derivative movement of the effective portion of cash flow hedges		$	—			$	(11,254	)		AOCI
Net gain (loss) reclassified from accumulated other comprehensive income into income due to realized gains (losses) associated with sales of production		$	15,143			$	2,149			Commodity Derivatives, net
Net gain (loss) recognized in income due to the movement of the ineffective portion of cash flow hedges		$	—			$	—			Commodity Derivatives, net

For the three months ended March 31, 2015 and 2014, changes in accumulated other comprehensive income for cash flow hedges, net of tax, are detailed below (in thousands). The reclassifications out of accumulated other comprehensive income are included in commodity derivatives, net in the condensed consolidated statements of loss and comprehensive loss.

 

		Three Months Ended March 31,
		2015				2014
Balance, beginning of period		$	44,471			$	729
Other comprehensive loss before reclassifications			—				(7,235	)
Settlements of cash flow hedges reclassified into earnings from accumulated other comprehensive income			(9,736	)			1,381
Net current period other comprehensive loss			(9,736	)			(5,854	)
Balance, end of period		$	34,735			$	(5,125	)

 

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Note 9.

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):

 

						Fair Value Measurement Using:
		Gross Carrying Amount				Level 1 Inputs				Level 2 Inputs				Level 3 Inputs
March 31, 2015 assets (liabilities):
Derivative assets		$	174,431			$	—			$	170,801			$	3,630
Derivative liabilities		$	(14,930	)		$	—			$	(14,668	)		$	(262	)
December 31, 2014 assets (liabilities):
Derivative assets		$	179,123			$	—			$	173,558			$	5,565
Derivative liabilities		$	(27,436	)		$	—			$	(19,785	)		$	(7,651	)

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 of inputs 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 significant unobservable inputs used in the fair value measurement of the Company’s Level 3 derivative contracts are forward NGL price curves and implied NYMEX natural gas volatilities. Significant changes in these unobservable forward NGL price curves would significantly impact the fair value measurements of our NGL swaps. Significant increases or decreases in the market implied volatilities will tend to have a net neutral impact on the fair value measurements of the NYMEX natural gas extendible collars, as the put and the call included in the collar would have directionally opposite changes in value. The following table discloses the significant unobservable inputs used in pricing these derivative contracts at March 31, 2015:

 

Commodity

Fair Value

Valuation Technique

Unobservable Input

Range

Weighted Average

(In thousands)

NGL Swaps

$

3,584

Discounted cash flow

Forward commodity price curve ($/gallon)

$0.16 - $1.17 (a)

$

0.47

(a)

Natural gas collar

$

(217

)

Option Model

Market implied volatilities of underlying futures (%)

24.22% - 42.81% (b)

—

 

(a)	Represents the market price range and weighted average market price that the Company has determined that market participants would take into account when pricing these NGL swaps.

(b)	Represents the range of market implied volatilities of the underlying natural gas NYMEX futures that the Company has determined that market participants will use when pricing the NYMEX natural gas extendible collars.

 

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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 March 31,
		2015				2014
Beginning balance		$	(2,086	)		$	(6,581	)
Total gains or losses:
Included in earnings			4,282				5,823
Included in other comprehensive income (loss)			—				—
Settlements			1,172				(3,951	)
Ending balance		$	3,368			$	(4,709	)
		Three Months Ended March 31,
		2015				2014
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain (loss) of assets still held		$	6,682			$	(740	)

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 March 31, 2015 and December 31, 2014, the estimated fair value of our long-term debt, including debt classified as current and cumulative redeemable preferred stock, was approximately $2.0 billion and $2.4 billion, respectively. Our measurements are based primarily upon quoted trading prices at March 31, 2015 and December 31, 2014 for our Senior Notes of 21.7% and 41.5% of par, respectively, and for our Second Lien Term Loan of 53.1% and 78.6% of par, respectively, and internal models for our RBL Revolver and cumulative redeemable preferred stock and therefore include both Level 2 and Level 3 measurements under the fair value hierarchy.

 

Note 10.

Debt

Total Debt

As of the dates presented, our total debt consisted of the following (in thousands):

 

		March 31, 2015				December 31, 2014
RBL Revolver		$	947,000			$	655,000
Second Lien Term Loan			1,000,000				1,000,000
9.75% Senior Notes			2,250,000				2,250,000
Total			4,197,000				3,905,000
Less: amounts classified as current			(4,197,000	)			(3,905,000	)
Amount of debt classified as long-term		$	—			$	—

 

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RBL Revolver

On March 18 2015, we amended the credit agreement governing the reserves-based revolving credit facility (the “RBL Revolver”) to, among other things:

 

•

reduce the borrowing base from $1.0 billion to $950.0 million which resulted in a payment of $46.0 million to reduce the amount outstanding on our RBL Revolver;

 

•

modify the financial performance covenant to provide that we shall maintain a ratio of consolidated total first lien debt to consolidated EBITDA of not more than 2.75 to 1.0 (up from 1.5 to 1.0 previously) as of the end of each fiscal quarter beginning with the first quarter of 2015 through and including the third quarter of 2015, at which point the first lien debt to consolidated EBITDA ratio reverts back to 1.5 to 1.0 at the end of the fourth quarter of 2015 and beginning with the first quarter of 2016 the credit agreement requires us to maintain a total debt to consolidated EBITDA ratio of not more than 4.5 to 1.0 as of the end of each fiscal quarter;

 

•

require minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due 2020 and the Second Lien Term Loan;

 

•

increase the collateral coverage minimum (as defined in the credit agreement) to at least 95% of the discounted present value of our restricted subsidiaries proved reserves;

 

•

require an automatic reduction in the borrowing base if we receive proceeds related to certain asset dispositions or early settlement of certain derivative financial instruments in the amount of such net proceeds; and

 

•

increase the interest rates on outstanding borrowings by 0.5%.

Our borrowing base under the RBL Revolver is based upon our estimated 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 March 31, 2015, we had no available borrowing capacity under the RBL Revolver after giving effect to outstanding letters of credit. During the three months ended March 31, 2015, the weighted average interest rate for borrowings under the RBL Revolver was 3.2%.

Maturities of Long-Term Debt

Contractual maturities of long-term debt outstanding at March 31, 2015 are as follows (in thousands):

 

2015		$	—
2016			947,000
2017			—
2018			1,000,000
2019			—
Thereafter			2,250,000
		$	4,197,000

Our debt is reflected as a current liability in our consolidated balance sheets at March 31, 2015 and December 31, 2014 due to uncertainty regarding our ability to comply with certain restrictive covenants contained in our credit facilities. See Note 1 for further information.

 

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Debt Covenants

As described above, the financial performance covenant in the credit agreement governing the RBL Revolver requires us to operate within established financial ratios. In addition, the March 2015 amendment to the credit agreement governing the RBL Revolver requires us to maintain a minimum liquidity on the date of certain interest payments made subsequent to July 1, 2015. Our ability to comply with these covenants depends upon our performance and indebtedness, each of which is impacted by numerous factors, including some that are outside of our control. The significant decline in oil, gas, and NGL prices has had a material impact to our cash flows, results of operations, and liquidity position. Those declines will limit our ability to comply with restrictive covenants contained in our various credit agreements. As a result of the uncertainty regarding our compliance with our restrictive covenants, our long-term debt with maturities summarized above is reflected as a current liability in our condensed consolidated balances sheet at March 31, 2015 and December 31, 2014. Additional factors impacting our financial performance and liquidity covenants include future production, returns generated by our capital program, future interest costs, future operating costs, future asset sales and future acquisitions, 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, sell assets, make acquisitions or investments, and incur additional indebtedness. In addition, the Debt Agreements contain reporting and administrative requirements, including, but not limited to, the form and content of the auditor’s report, 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.

Debt Issuance Costs

Costs incurred to obtain debt financing are capitalized as deferred costs and amortized over the contractual maturity period of the related debt. As a result of the March 2015 amendment to the RBL Revolver, which reduced the total commitment level to $950.0 million from $2.25 billion, approximately $15.1 million of unamortized debt issuance costs were written off and included in interest expense in the condensed consolidated statement of loss and comprehensive loss for the three months ended March 31, 2015. The unamortized amounts of debt related costs capitalized at March 31, 2015 and December 31, 2014 are $79.5 million and $100.7 million, respectively, and are included in deferred charges in the condensed consolidated balance sheets.

 

Note 11.

Stock Compensation

2011 Stock Incentive Plan

Stock Options

The following table provides information about our stock option activity under the 2011 Plan for the three months ended March 31, 2015:

 

		Number of Stock Options				Range of Exercise Prices		Weighted Average Exercise Price				Weighted Average Remaining Contractual Life (years)
Outstanding at December 31, 2014			74,060,900			$2.50 - $7.50		$	3.41				8.1
Options granted			—			—			—
Options forfeited			(1,930,940	)		$2.50			2.50
Options expired			(10,681,990	)		$2.50 - $5.00			2.51
Outstanding at March 31, 2015			61,447,970			$2.50 - $7.50		$	3.59				7.9
Vested and exercisable at March 31, 2015			22,383,800			$2.50 - $7.50		$	3.24				7.5

 

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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 following table summarizes information about stock based compensation related to stock options for the three months ended March 31, 2015 and 2014 (in thousands):

 

		Three Months Ended March 31,
		2015				2014
Grant date fair value for stock options granted during the period		$	—			$	2,404
Stock based compensation related to stock options:
Expensed during the period		$	12,435			$	11,094
Capitalized during the period			1,339				2,623
Total stock based compensation related to stock options during the period		$	13,774			$	13,717
Income tax benefit related to stock options		$	4,909			$	4,898

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
Risk-free interest rate			1.98 - 2.20	%
Expected term (years)			7.25
Expected volatility			49.70 - 49.86	%
Weighted average volatility			49.79	%
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 stock options issued under the 2011 Plan to non-officer employees is 16%. We assumed no future forfeitures of stock options issued to our officers.

As of March 31, 2015, unrecognized stock based compensation cost (either expensed or capitalized) related to unvested stock option awards was $49.1 million. The unrecognized cost is expected to be recognized over a weighted average period of 1.5 years.

Restricted Stock

The following table provides information about our restricted stock activity under the 2011 Plan for the three months ended March 31, 2015:

 

		Number of Shares				Weighted Average Grant Date Fair Value per Share
Outstanding at December 31, 2014			16,400,000			$	2.59
Stock of terminated officers			(1,900,000	)			—
Shares outstanding at March 31, 2015			14,500,000			$	2.62
Vested at March 31, 2015			—				—

 

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Compensation expense related to our restricted stock is valued at the date of award based on the estimated fair value of an unrestricted share (which includes 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 officers. The following table summarizes information about stock based compensation related to restricted stock for the three months ended March 31, 2015 and 2014 (in thousands):

 

		Three Months Ended March 31,
		2015				2014
Grant date fair value for restricted stock granted during the period		$	—			$	19,125
Stock based compensation related to restricted stock:
Expensed during the period		$	10,433			$	1,167
Capitalized during the period			—				—
Total stock based compensation related to restricted stock during the period		$	10,433			$	1,167
Income tax benefit related to restricted stock		$	3,719			$	417

As of March 31, 2015, unrecognized stock based compensation cost related to unvested restricted stock awards was $13.0 million. The unrecognized stock based compensation expense will be recognized through September 1, 2015.

Officer Agreements

During the year ended December 31, 2014, the Compensation Committee of the Board of Directors approved officer retention letter agreements and adopted the Samson Resources Corporation Voluntary Severance Plan for Officers (the “Officer Voluntary Severance Plan”). Pursuant to the terms of these arrangements, officers that remained employed by the Company (“Remaining Officers”) through September 1, 2015 (the “Retention Date”) and continued their employment after such date were entitled to receive (i) a grant of shares of vested restricted stock in an amount equal to two times the sum of such officer’s annual base salary and target bonus amount (the “Retention Amount”), (ii) the accelerated vesting of all unvested equity awards held by such officer as of November 14, 2014, with vesting occurring as of the Retention Date (the “Accelerated Vesting Benefit”), and (iii) special temporary put and call rights for all vested equity awards held by such officer that were exercisable over a specified period following the Retention Date and would allow for repurchase based on the fair market value of the Company’s common stock as of the Retention Date (the “Temporary Put and Call Rights”). Subject to certain conditions, Remaining Officers that voluntarily terminated their employment as of the Retention Date would have been entitled to receive (i) the payment of the Retention Amount in cash over a specified period, (ii) the Accelerated Vesting Benefit, (iii) certain severance-related benefits, including a pro-rated portion of the 2015 target bonus and other customary benefits, and (iv) the Temporary Put and Call Rights. Officers that were terminated by the Company other than for “cause” on or prior to the Retention Date were entitled to receive payments and benefits substantially similar to those described above. The Accelerated Vesting Benefit increased compensation expense in 2014 and 2015, but does not change the total estimated compensation expense to be recognized for previously granted awards.

As provided for in the retention letter agreements, the March 2015 workforce reduction (described in Note 12) triggered severance benefits to be paid to certain officers. The terminated officers signed customary release agreements which included the cancellation of all equity awards. The officer terminations resulted in an acceleration of unrecognized stock based compensation expense associated with previously granted stock options and restricted stock of $5.6 million during the quarter ended March 31, 2015.

In March 2015, agreements were executed with each remaining officer (collectively, the “March 2015 Officer Agreements”) which had the effect of canceling the provisions in the retention letter agreements providing for the granting of vested restricted stock and the establishment of the Temporary Put and Call Rights and canceling the Officer Voluntary Severance Plan. In exchange for relinquishing the majority of benefits previously provided for in the retention letter agreements and Officer Voluntary Severance Plan, the remaining officers received payments in the second quarter of 2015 equal to one-half of the Retention Amount provided in the retention letter agreements conditioned upon the officer continuing employment with the Company through September 1, 2015, unless the officer is terminated by the Company other than for “cause”. In addition, the March 2015 Officer Agreements provided for quarterly incentive payments through the third quarter of 2015.

 

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Due to the cancellation of the Temporary Put and Call Rights which occurred with the March 2015 Officer Agreements, all stock options and restricted stock previously granted to the remaining officers are accounted for as equity awards instead of liability awards at March 31, 2015. Consequently, approximately $2.1 million was reclassified from accrued and other current liabilities to additional paid in capital in the Company’s condensed consolidated balance sheet. Compensation expense associated with previous grants of stock options and restricted stock will continue to be based on the original grant date fair value of the awards.

We estimate that the total payments to remaining officers pursuant to the provisions of the March 2015 Officer Agreements will be significant. The liability recorded associated with the various components of the officer retention agreements, the Officer Voluntary Severance Plan, and the March 2015 Officer Agreements is included in accrued compensation and benefits, a component of accrued and other current liabilities in the Company’s condensed consolidated balance sheet.

Cash Incentive Awards

During the year ended December 31, 2014, the Compensation Committee of the Board of Directors approved providing cash based incentive awards for certain employees (the “Cash Incentive Awards”). In March 2015, the Cash Incentive Awards were modified so that vesting will be on an accelerated basis beginning in the first quarter of 2015 through the third quarter of 2015. Individuals must be employed by the Company on the date of payment in order to receive the applicable portion of the award. Half of an individual’s Cash Incentive Award is subject to repayment if the recipient voluntarily leaves the Company prior to September 1, 2015. The liability recorded associated with the cash incentive awards is included in accrued compensation and benefits, a component of accrued and other current liabilities in the Company’s condensed consolidated balance sheet.

 

Note 12.

Restructuring

In March 2015, we announced a plan to reduce our workforce by approximately 35% in connection with a corporate restructuring. We recorded approximately $34.6 million of expense related to the restructuring for the three months ended March 31, 2015, which represented direct costs associated with our plan to reorganize our workforce. The following is a reconciliation of the beginning and ending liability balances associated with our corporate restructuring (in thousands):

 

Liability at December 31, 2014		$	—
Additions for the three months ended March 31, 2015			26,774
Payments			(3,509	)
Liability at March 31, 2015		$	23,265

The liability associated with our restructuring plan is included in accrued and other current liabilities in our condensed consolidated balance sheet at March 31, 2015.

The following is a detail of the components of the restructuring expense for the three months ended March 31, 2015:

 

Severance benefits for employees and officers		$	22,068
Accelerated expense recognition associated with previous grants under our incentive compensation plans			12,066
Other		$	432
Total		$	34,566

The restructuring expense related to terminated officers represents the total expected severance related payments in excess of previously recognized compensation expense associated with the officer retention letter agreements.

 

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Note 13.

Supplemental Information to Condensed Statements of Cash Flows

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

 

		Three Months Ended March 31,
		2015				2014
Interest paid (net of capitalized interest of $79,884 and $123,263, respectively)		$	49,610			$	10,440
Income taxes paid, net		$	21			$	582

Supplemental Non-Cash Investing and Financing Activities

Total payables included in accounts payable and accrued liabilities related to acquisition and drilling expenditures for oil and gas properties for the Company were $126.8 million and $111.2 million at March 31, 2015 and 2014, respectively, and $82.5 million and $77.0 million at December 31, 2014 and 2013, respectively.

 

Note 14.

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 $1.8 million and $1.6 million for the three months ended March 31, 2015 and 2014, respectively. Rental expense is included in general and administrative expenses in the condensed consolidated statements of loss and comprehensive loss.

Other Commercial Commitments

During the first quarter of 2015, we terminated approximately $12.5 million of our remaining drilling rig commitments as of December 31, 2014 and incurred rig termination fees of approximately $5.2 million as a result.

Letters of Credit and Bonds

As of March 31, 2015, we had outstanding irrevocable letters of credit totaling approximately $2.0 million to guarantee payment of certain marketing and workers compensation insurance obligations. Additionally, at March 31, 2015, we had approximately $12.8 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. 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. No liability has been recorded at March 31, 2015 associated with the Change in Control Severance Plans.

Employee Severance Plan

Effective September 1, 2014, the Company adopted the Samson Resources Corporation Job Elimination Severance Plan for Non-Officers (the “Employee Severance Plan”) that applies to all eligible full-time non-officer employees. The Employee Severance Plan generally provides for severance payments to such employees if employment is involuntarily terminated in connection with a corporate restructuring, downsizing, workforce reduction, asset sales, or similar reason through September 1, 2015.

 

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In March 2015, we announced reduction in workforce of approximately 35% of our employees in connection with a corporate restructuring. As a result of the workforce reduction, we expect to pay approximately $33.9 million of severance benefits in the first and second quarters of 2015 to terminated employees under the Employee Severance Plan in addition to other accrued compensation and benefits. We have recorded a liability of approximately $20.7 million at March 31, 2015 associated with severance benefits under the Employee Severance Plan, which is included in accrued restructuring charges, a component of accrued and other current liabilities in our condensed consolidated balance sheet at March 31, 2015.

The employment agreement with our Chief Executive Officer provides for the payment of cash compensation and certain other benefits, which could be material, in the event of a severance or change in control depending upon the circumstances.

Litigation and Contingencies

We are involved in various matters incidental to our operations and business that might give rise to a gain or 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. Expected recovery of any amount in excess of the related recorded contingent loss or related to a contingent gain is recognized if and when all contingencies related to the recovery have been resolved, which generally corresponds with the receipt of cash in excess of the related recorded contingent loss. 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 2014, in connection with an ongoing audit on behalf of a federal regulator, we began reviewing the manner in which our obligations to make royalty payments for natural gas production on federal leases should be determined. The review 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 review 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 the 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 practices in certain states was commenced and we entered into a Voluntary Disclosure Agreement (“VDA”) with the state of Oklahoma related to our unclaimed property reporting practices. The unclaimed property audit and VDA process is ongoing and we expect resolution of both processes to occur in 2015.

As of March 31, 2015, our total accrual for all loss contingencies was $11.3 million, of which $3.7 million was included in oil and natural gas revenues held for distribution and $7.6 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 our accrual will change as facts and circumstances change and any such changes may be material.

 

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Note 15.

Income Taxes

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

 

		Three Months Ended March 31,
		2015				2014
Deferred taxes:
Federal			(266,608	)			(440	)
State			(4,951	)			(9	)
Income tax benefit		$	(271,559	)		$	(449	)

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

 

		Three Months Ended March 31,
		2015				2014
U.S. statutory rate			35	%			35	%
State taxes			1	%			1	%
Other			0	%			(5	)%
			36	%			31	%

Samson has recognized approximately $603.5 million of deferred tax assets related to various carryforwards available to offset future income taxes which expire between 2015 and 2035. These carryforwards are primarily related to expensing intangible drilling costs and accelerated depreciation deductions. We have not recorded a valuation allowance associated with our deferred tax assets as we believe it is more likely than not that the assets will be realized. Our expectations are based upon current estimates of taxable income during future periods, considering limitations on utilization of these benefits as set forth by tax regulations and based on the reversing effects of our deferred tax liabilities. Significant changes in our estimates caused by variables such as future oil, gas and natural gas liquids prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Samson will generate any specific level of continuing taxable earnings.

Samson’s primary deferred tax liability is due to the fact that the book value of its oil and gas assets exceeds its tax basis in those assets. At March 31, 2015, the tax basis in our oil and gas assets was approximately $1.1 billion.

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 March 31, 2015.

 

Note 16.

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 quarterly payments of $5.0 million. As required by the agreement, the aggregate annual fee and corresponding quarterly payments increases 5.0% each year. We incurred $5.8 million and $5.5 million in the three months ended March 31, 2015 and 2014, respectively. This fee is included in the condensed consolidated statements of loss and comprehensive loss as related party management fee. In March 2015, the shareholders consented to the extension of time for the payment of the quarterly management fee until the earlier of (i) September 30, 2015 and (ii) such time as the shareholders determine to reinstate such payment. The extension does not change the amount of management fee incurred pursuant to the consulting agreement.

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 $6.0 million for the three months ended March 31, 2015. There were no receipts under the Offtake Agreement for the three months ended March 31, 2014.

 

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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 March 31, 2015 and 2014, we paid approximately $0.2 million and $0.1 million, 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 March 31, 2015 and 2014, we paid approximately $0.1 million and $0.4 million, respectively, for supplies from Bell Supply Company LLC.

Since 2009, we have, from time to time, engaged the services of Alliant Insurance Services, Inc. (“Alliant”), an insurance brokerage firm. In 2012, one or more affiliates of KKR acquired a controlling ownership interest in Alliant. For the three months ended March 31, 2015 and 2014, we did not make any payments to Alliant for insurance brokerage services.

We have, from time to time, engaged Select Energy Services, LLC and its subsidiary, Peak Oilfield Services LLC, for water hauling, tank rental and other well-site water management and equipment rental services. Select Energy Services, LLC is an affiliate of Crestview Partners II GP, L.P. One of our directors is a managing director of the investment manager of the funds affiliated with Crestview Partners II GP, L.P. and serves as a director of Select Energy Services, LLC. For the three months ended March 31, 2015 and 2014, we paid approximately $0.1 million in the aggregate for each period to Select Energy Services, LLC and Peak Oilfield Services LLC.

In March 2015, we completed the sale of certain of our oil and gas assets to an entity affiliated with Natural Gas Partners in exchange for approximately $48.0 million. Investment funds affiliated with Natural Gas Partners IX, L.P. indirectly own interests in Samson Aggregator.

The Company is party to an agreement with CoreTrust Purchasing Group (“CoreTrust”), a group purchasing program that maintains relationships with certain vendors, from which participating companies may purchase products or services pursuant to the terms of the purchasing program. Since April 2013, the Company has, from time to time, purchased certain products and services from various vendors through the CoreTrust purchasing program. One or more affiliates of KKR have an indirect ownership interest in CoreTrust.

 

Note 17.

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.

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, the Subsidiary Guarantors and the non-guarantor subsidiaries 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.

 

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SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF MARCH 31, 2015

(In thousands)

 

		Samson Resources Corporation (Parent Guarantor)				Samson Investment Company (Issuer)				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
Cash and cash equivalents		$	—			$	161,815			$	32,087			$	154			$	—			$	194,056
Accounts receivable, net			—				—				147,592				—				—				147,592
Intercompany receivables			65,668				231,272				—				—				(296,940	)			—
Other current assets			—				—				124,152				—				—				124,152
Oil and gas properties, net			—				—				4,174,095				—				—				4,174,095
Other property and equipment, net			—				—				287,744				—				—				287,744
Loss in excess of investment in subsidiaries			(158,388	)			3,372,792				—				—				(3,214,404	)			—
Other noncurrent assets			22,930				301,069				63,872				22,698				(253,067	)			157,502
Total assets		$	(69,790	)		$	4,066,948			$	4,829,542			$	22,852			$	(3,764,411	)		$	5,085,141
Accounts payable		$	—			$	—			$	93,996			$	2,241			$	—			$	96,237
Intercompany payables			—				—				277,676				19,264				(296,940	)			—
Accrued and other current liabilities			5,788				28,336				179,513				43				—				213,680
Other current liabilities			—				—				98,051				—				—				98,051
Debt classified as current			—				4,197,000				—				—				—				4,197,000
Deferred income tax liabilities			—				—				718,928				—				(253,067	)			465,861
Other noncurrent liabilities			—				—				89,890				—				—				89,890
Cumulative preferred stock subject to mandatory redemption			206,865				—				—				—				—				206,865
Puttable common stock			1,000				—				—				—				—				1,000
Shareholders’ equity (deficit)			(283,443	)			(158,388	)			3,371,488				1,304				(3,214,404	)			(283,443	)
Total liabilities and shareholders’ equity (deficit)		$	(69,790	)		$	4,066,948			$	4,829,542			$	22,852			$	(3,764,411	)		$	5,085,141

 

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SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2014

(In thousands)

 

		Samson Resources Corporation (Parent Guarantor)				Samson Investment Company (Issuer)				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
Cash and cash equivalents		$	—			$	281			$	23,451			$	94			$	—			$	23,826
Accounts receivable, net			—				—				173,524				—				—				173,524
Intercompany receivables			36,045				200,321				—				—				(236,366	)			—
Other current assets			—				—				139,231				—				—				139,231
Oil and gas properties, net			—				—				4,822,623				—				—				4,822,623
Other property and equipment, net			—				—				291,761				—				—				291,761
Investment in subsidiaries			336,358				3,802,678				—				—				(4,139,036	)			—
Other noncurrent assets			22,930				322,231				45,696				19,557				(253,067	)			157,347
Total assets		$	395,333			$	4,325,511			$	5,496,286			$	19,651			$	(4,628,469	)		$	5,608,312
Accounts payable		$	—			$	—			$	19,555			$	536			$	—			$	20,091
Intercompany payables			—				—				218,664				17,702				(236,366	)			—
Accrued and other current liabilities			—				84,153				240,442				35				—				324,630
Other current liabilities			—				—				117,156				—				—				117,156
Debt classified as current			—				3,905,000				—				—				—				3,905,000
Deferred income tax liabilities			—				—				999,904				—				(253,067	)			746,837
Other noncurrent liabilities			—				—				99,265				—				—				99,265
Cumulative preferred stock subject to mandatory redemption			202,808				—				—				—				—				202,808
Puttable common stock			1,000				—				—				—				—				1,000
Shareholders’ equity			191,525				336,358				3,801,300				1,378				(4,139,036	)			191,525
Total liabilities and shareholders’ equity		$	395,333			$	4,325,511			$	5,496,286			$	19,651			$	(4,628,469	)		$	5,608,312

 

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SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF INCOME (LOSS) AND

COMPREHENSIVE INCOME (LOSS)

FOR THE THREE MONTHS ENDED MARCH 31, 2015

(In thousands)

 

		Samson Resources Corporation (Parent Guarantor)				Samson Investment Company (Issuer)				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
Total revenues		$	—			$	—			$	206,176			$	—			$	—			$	206,176
Total operating expenses			5,893				—				894,139				115				—				900,147
Operating loss			(5,893	)			—				(687,963	)			(115	)			—				(693,971	)
Interest income (expense), net			(2,373	)			(61,783	)			29				—				—				(64,127	)
Equity in earnings of subsidiaries			(485,011	)			(445,249	)			—				—				930,260				—
Other expense, net			—				—				(3,792	)			—				—				(3,792	)
Income (loss) before income taxes			(493,277	)			(507,032	)			(691,726	)			(115	)			930,260				(761,890	)
Income tax benefit			(2,946	)			(22,021	)			(246,551	)			(41	)			—				(271,559	)
Net income (loss)			(490,331	)			(485,011	)			(445,175	)			(74	)			930,260				(490,331	)
Total other comprehensive income (loss), net of tax			(9,736	)			(9,736	)			(9,736	)			—				19,472				(9,736	)
Total comprehensive income (loss)		$	(500,067	)		$	(494,747	)		$	(464,911	)		$	(74	)		$	949,732			$	(500,067	)

 

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SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF INCOME (LOSS) AND

COMPREHENSIVE INCOME (LOSS)

FOR THE THREE MONTHS ENDED MARCH 31, 2014

(In thousands)

 

		Samson Resources Corporation (Parent Guarantor)				Samson Investment Company (Issuer)				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Eliminations				Consolidated
Total revenues		$	—			$	—			$	250,928			$	—			$	—			$	250,928
Total operating expenses			5,648				225				225,709				209				—				231,791
Operating income (loss)			(5,648	)			(225	)			25,219				(209	)			—				19,137
Interest expense, net			(600	)			(19,846	)			(30	)			—				—				(20,476	)
Equity in earnings of subsidiaries			3,319				17,265				—				—				(20,584	)			—
Other income (expense), net			—				—				65				(197	)			—				(132	)
Income (loss) before income taxes			(2,929	)			(2,806	)			25,254				(406	)			(20,584	)			(1,471	)
Income tax provision (benefit)			(1,907	)			(6,125	)			7,707				(124	)			—				(449	)
Net income (loss)			(1,022	)			3,319				17,547				(282	)			(20,584	)			(1,022	)
Total other comprehensive income (loss), net of tax			(5,854	)			(5,854	)			(5,854	)			—				11,708				(5,854	)
Total comprehensive income (loss)		$	(6,876	)		$	(2,535	)		$	11,693			$	(282	)		$	(8,876	)		$	(6,876	)

 

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SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 2015

(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		$	(11,681	)		$	(49,640	)		$	82,449			$	(656	)		$	—			$	20,472
Investing activities:
Capital expenditures—oil and gas properties			—				—				(195,060	)			—				—				(195,060	)
Capital expenditures—other property and equipment			—				—				(7,794	)			—				—				(7,794	)
Proceeds from divestitures—oil and gas properties			—				—				60,112				—				—				60,112
Proceeds from divestitures—other property and equipment			—				—				500				—				—				500
Advances to parent/subsidiary			—				(80,826	)			—				—				80,826				—
Net cash provided by (used in) investing activities			—				(80,826	)			(142,242	)			—				80,826				(142,242	)
Financing activities:
Advances from issuer			11,681				—				68,429				716				(80,826	)			—
Proceeds from revolver			—				338,000				—				—				—				338,000
Repayment of revolver			—				(46,000	)			—				—				—				(46,000	)
Net cash provided by (used in) financing activities			11,681				292,000				68,429				716				(80,826	)			292,000
Net change in cash			—				161,534				8,636				60				—				170,230
Cash and cash equivalents at beginning of period			—				281				23,451				94				—				23,826
Cash and cash equivalents at end of period		$	—			$	161,815			$	32,087			$	154			$	—			$	194,056

 

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SAMSON RESOURCES CORPORATION

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 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		$	(5,638	)		$	(10,253	)		$	119,882			$	(788	)		$	—			$	103,203
Investing activities:
Capital expenditures—oil and gas properties			—				—				(263,566	)			—				—				(263,566	)
Capital expenditures—other property and equipment			—				—				(5,035	)			—				—				(5,035	)
Proceeds from divestitures—oil and gas properties			—				—				5,502				—				—				5,502
Proceeds from divestitures—other property and equipment			—				—				3				—				—				3
Advances to parent/subsidiary			—				(151,828	)			—				—				151,828				—
Net cash provided by (used in) investing activities			—				(151,828	)			(263,096	)			—				151,828				(263,096	)
Financing activities:
Advances from issuer			7,828				—				143,207				793				(151,828	)			—
Proceeds from revolver			—				172,000				—				—				—				172,000
Repayment of revolver			—				(10,000	)			—				—				—				(10,000	)
Repurchase of stock			(2,190	)			—				—				—				—				(2,190	)
Net cash provided by (used in) financing activities			5,638				162,000				143,207				793				(151,828	)			159,810
Net change in cash			—				(81	)			(7	)			5				—				(83	)
Cash and cash equivalents at beginning of period			—				238				399				90				—				727
Cash and cash equivalents at end of period		$	—			$	157			$	392			$	95			$	—			$	644

 

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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 our 2014 Annual Report on Form 10-K. 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 Mountain region, and our East Division, which includes properties primarily in the Mid-Continent and East Texas regions. Our assets include a number of potential growth opportunities, including a significant amount of undeveloped properties with leases held by current production that we believe contain reserves from which we could realize value in the event of future increases in oil and natural gas prices and adequate liquidity, among other factors.

Recent Developments

In 2014, our strategic focus was evaluating our asset base for the purpose of determining which assets we considered core assets capable of supporting long-term, sustainable drilling programs with acceptable returns. For non-core assets, we pursued divestiture opportunities, or other transactions to monetize the assets. We intended to use the proceeds of any divestitures to support our capital program or increase available funds for use in acquisitions of oil and gas properties that would be complimentary to existing core assets or create a new core asset.

In the last half of 2014, we began actively marketing larger packages of oil and gas properties for divestiture. In the first quarter of 2015, we closed a transaction to sell properties associated with the Arkoma Basin in Oklahoma for approximately $48.0 million. We have not currently entered into agreements to divest other larger packages, including our Bakken, Wamsutter, San Juan and non-core Mid-Con assets, because we perceived the value offered was less than the value of retaining those properties when economic factors and the impact to our credit position were considered. The offer prices were impacted by the rapid decline in the market price for oil, gas, and NGLs that occurred in the fourth quarter of 2014 with continued weakness in 2015.

The significant decline in oil, gas, and NGL prices has had a material impact to our cash flows, results of operations, and liquidity position. Those declines will limit our ability to comply with restrictive covenants contained in our various credit agreements. Uncertainty regarding our liquidity and our ability to comply with restrictive covenants contained in our various credit agreements, the consequences of the uncertainty, and management’s plans to address the uncertainty are described in Note 1 to our condensed consolidated financial statements included in Part I, Item 1—“Financial Statements” of this report.

In March 2015, we amended the credit agreement governing the RBL Revolver to, among other things, modify the financial performance covenant and add a restrictive covenant requiring us to maintain minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due 2020 and the Second Lien Term Loan.

 

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As a result of declining product prices and the significant uncertainty regarding our liquidity, we have adjusted our short-term strategic focus. Our 2015 capital budget does not contemplate significant drilling and completion activities to occur subsequent to the first quarter of 2015. In addition, in March 2015, we began implementing a plan to reduce long-term recurring operating expenses which included a reduction of approximately 35% of our workforce and initiatives to reduce other recurring general and administrative expenses and lease operating expenses. Furthermore, we have engaged advisors to assist with the evaluation of our options to address our liquidity position and evaluate strategic alternatives. The strategic alternatives may include, but not be limited to, seeking a restructuring, amendment or refinancing of our outstanding debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that the company will be able to successfully restructure its indebtedness, improve our liquidity position, complete any strategic transactions or comply with future debt covenant requirements. For additional information, see “Liquidity and Capital Resources” section of this report.

Operating Expense Reductions

We have begun implementing a plan to lower long-term, recurring operating expenses. In March 2015, we announced the reduction of approximately 35% of our workforce in connection with a corporate restructuring. We are also pursuing reductions in recurring general and administrative expenses that were not compensation related and are evaluating ways to reduce production costs in an environment where we expect declining service costs in response to changing industry conditions.

While we believe our actions will better align our cost structure with our company’s financial condition in the long term, we do expect increases in short-term, non-recurring operating expenses associated with our cost reduction plan and the strategic initiatives described above. For example, we expect significant increases in consulting costs related to strategic advisors and increases in costs associated with our workforce reduction, including but not limited to: severance benefits paid pursuant to our officer retention agreements and employee severance plan and accelerated expense recognition of cash and stock based incentive awards.

Restructuring Charges

In connection with our corporate reorganization and related workforce reductions, certain costs we incurred are classified as restructuring charges in our condensed consolidated financial statements. Generally, direct costs associated with our plan to reorganize our workforce are characterized as restructuring costs. The components of costs classified as restructuring charges are described in Note 12 to our condensed consolidated financial statements included in Part I, Item 1—“Financial Statements” of this report. We have also engaged strategic advisors to assist with evaluating alternatives to address our liquidity position and other strategic alternatives, which may include restructuring our outstanding debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. Costs incurred related to our strategic advisors are included in general and administrative expenses in our condensed consolidated financial statements, even though a significant portion of those costs may be non-recurring expenses. For additional information, see “Results of Operations” section of this report.

2015 Capital Budget

Our 2015 capital budget is approximately $156.5 million (excluding capitalized interest and internal costs). Approximately 60% of our 2015 capital budget, or $93.2 million, is allocated primarily to drilling and completion activities for wells where drilling began in 2014 or early 2015. A significant portion of our 2015 capital budget is associated with mechanical integrity, safety and environmental compliance programs. As a result, we expect production will decline until it is offset with production increases attributable to a new capital program. Consistent with our historical practice, we periodically review our capital expenditures and adjust our capital program based on liquidity, commodity prices and expected performance. Consequently, actual capital expenditures may be more or less than amounts budgeted for 2015.

Basis of Presentation

The following discussion and analysis addresses significant changes in our results of operations and capital resources for the three months ended March 31, 2015, as compared to the three months ended March 31, 2014, and in our financial condition and liquidity since December 31, 2014. 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 our 2014 Annual Report.

 

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Market Conditions

Prices for our products are inherently volatile and changes in product prices can significantly impact our revenue, net loss and cash flows. The following table sets forth the average market prices for natural gas, oil and NGLs for the three months ended March 31, 2015 and 2014:

 

		Three Months Ended March 31,
		2015				2014
Average prices:
Natural gas (MMBtu) (a)		$	2.98			$	4.94
Oil (Bbl) (b)		$	48.64			$	98.68
NGLs (Bbl) (c)		$	19.75			$	42.49

Average market prices for natural gas and oil decreased significantly in the last part of 2014 with continued weakness into 2015. If product prices remain at levels experienced during the fourth quarter of 2014 and the first quarter of 2015 throughout 2015, we expect significantly lower revenues and operating cash flows compared to historical results. In addition, lower product prices will also contribute to potentially material impairment expense in future periods resulting from our full cost ceiling tests.

 

(a)	Based on NYMEX last day settlements.

(b)	Based on NYMEX calendar month average settlements.

(c)	Based on Samson’s NGL component blend utilizing OPIS daily mid-point pricing for Conway and Mont Belvieu.

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. Oil, natural gas and NGL revenues are impacted by the volume of product sold and our realized price. The following tables set forth information regarding our oil, natural gas and NGL revenues for the three months ended March 31, 2015 and 2014 (in thousands):

 

		Crude Oil				Natural Gas				NGLs				Total
Revenue for the three months ended March 31, 2014		$	112,126			$	150,041			$	46,090			$	308,257
Change due to volumes			1,433				(2,430	)			(722	)			(1,719	)
Change due to price			(60,926	)			(68,904	)			(28,918	)			(158,748	)
Revenue for the three months ended March 31, 2015		$	52,633			$	78,707			$	16,450			$	147,790

 

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Pricing

The following table sets forth information regarding average realized sales prices for the three months ended March 31, 2015 and 2014:

 

		Three Months Ended March 31,
		2015				2014				Change
Average realized sales prices:
Crude oil, unhedged ($/Bbl)		$	41.90			$	91.76				(54	)%
Natural gas, unhedged ($/Mcf)		$	2.43			$	4.49				(46	)%
NGLs, unhedged ($/Bbl)		$	14.74			$	39.55				(63	)%
Average realized price, unhedged ($/Mcfe)		$	3.17			$	6.46				(51	)%
Crude oil, hedged ($/Bbl) (a)		$	52.52			$	82.05				(36	)%
Natural gas, hedged ($/Mcf) (a)		$	3.07			$	3.84				(20	)%
NGLs, hedged ($/Bbl) (a)		$	15.79			$	36.16				(56	)%
Average realized price, hedged ($/Mcfe)		$	3.93			$	5.67				(31	)%

 

(a)	The effects of hedges include cash settlements for both derivatives designated as cash flow hedges and those not designated as cash flow hedges for the period ending March 31, 2014. Effective January 1, 2015, we discontinued hedge accounting on all of our existing 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 as a result of many factors, such as geography. Most of our natural gas is sold on a monthly basis using a monthly index price or a daily basis using daily market prices for a given period. Our average realized natural gas price decreased for the three months ended March 31, 2015 primarily as a result of lower 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 months ended March 31, 2015 and 2014, approximately 57% and 83%, 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 fluctuations, changes in demand, 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 as a result of regional fundamentals. Our realized crude oil price for the three months ended March 31, 2015 decreased primarily as a result of these market forces.

We utilize fixed price swaps to manage our exposure to crude oil prices. For the three months ended March 31, 2015, approximately 25% of our crude oil production was economically hedged with financial derivatives. For the three months ended March 31, 2014, all of our crude oil production was economically hedged with financial derivatives.

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 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 decreased for the three months ended March 31, 2015 as a result of a decrease in overall market price for NGLs.

We utilize fixed price swaps to manage our exposure to NGL pricing. For the three months ended March 31, 2015 and 2014, approximately 6% and 54%, respectively, of our NGL production was economically hedged with financial derivatives.

 

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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 loss and comprehensive loss in the periods in which they occur. Accordingly, this could result in future earnings that are more volatile.

Prior to January 1, 2015, we had 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 were recorded through other comprehensive income (loss) and did not impact net income (loss) until the underlying physical transaction settled. Once the underlying physical transaction settled, the cash settlement gain or loss on the related cash flow hedge was recorded as commodity derivatives, net in our condensed consolidated statements of loss and comprehensive loss. Any change in the fair value of cash flow hedges resulting from ineffectiveness was recognized in current earnings in commodity derivatives, net.

Effective January 1, 2015, we discontinued hedge accounting on all of our existing cash flow hedges and began accounting for these derivatives using the mark-to-market accounting method. At the time of hedge de-designation, the net gains and losses deferred in accumulated other comprehensive income associated with these contracts remain and will be reclassified to earnings in the periods the original forecasted hedged transaction occurs, unless the forecasted transaction becomes not probable of occurring, which will result in an immediate reclassification to earnings.

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

 

		Three Months Ended March 31,
		2015				2014
Derivative settlements:
Natural gas derivatives		$	20,918			$	(21,878	)
Oil derivatives			13,340				(11,863	)
NGL derivatives			1,172				(3,951	)
Total settlements			35,430				(37,692	)
Total gains (losses) on derivatives:
Natural gas derivatives			26,175				(17,713	)
Oil derivatives			(1,956	)			(3,861	)
NGL derivatives			(1,263	)			1,937
Total gains (losses) on derivatives			22,956				(19,637	)
Total commodity derivatives, net		$	58,386			$	(57,329	)

 

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Production

The following table sets forth information regarding our average net daily production for the three months ended March 31, 2015 and 2014:

 

		Three Months Ended March 31,
		2015				2014				Change
Production volumes:
Natural gas (MMcf/d):
West Division
Williston			1.4				1.4				—
Powder River			2.5				2.0				0.5
Greater Green River			26.1				33.1				(7.0	)
San Juan			74.5				84.2				(9.7	)
East Division
Mid-Continent			97.7				122.3				(24.6	)
East Texas			157.1				125.6				31.5
Other (a)			0.6				1.7				(1.1	)
Total			359.9				370.3				(10.4	)
Crude oil (Bbl/d):
West Division
Williston			4,201.4				3,404.8				796.6
Powder River			3,950.2				3,147.1				803.1
Greater Green River			707.6				871.4				(163.8	)
San Juan			0.5				0.1				0.4
East Division
Mid-Continent			3,543.4				4,961.9				(1,418.5	)
East Texas			1,529.1				1,157.1				372.0
Other (a)			25.3				37.1				(11.8	)
Total			13,957.5				13,579.5				378.0
NGL (Bbl/d):
West Division
Williston			188.5				163.1				25.4
Powder River			220.3				145.3				75.0
Greater Green River			2,558.6				2,969.5				(410.9	)
San Juan			5.2				58.8				(53.6	)
East Division
Mid-Continent			5,088.9				7,008.0				(1,919.1	)
East Texas			4,319.6				2,557.1				1,762.5
Other (a)			21.6				45.0				(23.4	)
Total			12,402.7				12,946.8				(544.1	)
Combined Production (MMcfe/d):
West Division
Williston			28				23				5
Powder River			28				22				6
Greater Green River			46				56				(10	)
San Juan			74				84				(10	)
East Division
Mid-Continent			149				194				(45	)
East Texas			192				148				44
Other (a)			1				2				(1	)
Total			518				529				(11	)

 

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

 

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Natural Gas Production

Three months ended March 31, 2015—Average daily natural gas production decreased 2.8% as compared to the three months ended March 31, 2014. Contributing to lower daily production volumes were divestitures primarily in our Greater Green River and Mid-Continent business units. Additionally, production volumes were negatively impacted by declines in base production of dry gas assets, primarily in the San Juan and Mid-Continent business units. Partially offsetting declines in base production was an increase in production in our East Texas business unit resulting from new wells and approximately 9 MMcf/d of production from our acquisition of producing properties in December 2014.

Crude Oil Production

Three months ended March 31, 2015—Average daily crude oil production increased 2.8% as compared to the three months ended March 31, 2014. The increase was attributable to new production during the period resulting from our drilling programs in the Williston, Powder River and East Texas business units. These increases were partially offset with declines in base production from wells in our Mid-Continent and Greater Green River business units.

NGL Production

Three months ended March 31, 2015—Average daily NGL production decreased 4.2% as compared to the three months ended March 31, 2014. The decrease was attributable to declines in base production from wells in our Greater Green River and Mid-Continent business units; offset by new production due to drilling activity in our Williston, Powder River and East Texas business units. Also contributing to the increase in NGL production in our East Texas business unit was an increase in approximately 350 Bbl/d of production from our acquisition of producing properties in December 2014.

Operating Expenses

The following tables set forth information regarding operating expenses for the three months ended March 31, 2015 and 2014 (in thousands, except per unit data):

 

		Three Months Ended March 31,
		2015				2014
Operating expenses:
Lease operating		$	54,053			$	45,478
Production and ad valorem taxes			11,993				20,477
Depreciation, depletion and amortization			103,762				118,146
Impairment of oil and gas properties			629,517				—
Asset retirement obligation accretion			1,610				1,198
Restructuring charges			34,566				—
Related party management fee			5,788				5,512
General and administrative			58,858				40,980
Total operating expenses		$	900,147			$	231,791
		Three Months Ended March 31,
		2015				2014
Average cost per unit of combined production ($ per Mcfe):
Production costs:
Lease operating expense (1)		$	1.16			$	0.95
Production and ad valorem taxes			0.26				0.43
Total production cost per unit		$	1.42			$	1.38
Depreciation, depletion and amortization		$	2.23			$	2.48
General and administrative expenses (2)		$	1.26			$	0.86

 

(1)	Includes stock based compensation expense of $0.02 and $0.05 for the three months ended March 31, 2015 and 2014, respectively.

(2)	Includes stock based compensation expense of $0.29 and $0.21 for the three months ended March 31, 2015 and 2014, respectively.

 

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Lease operating expenses (“LOE”). LOE increased by $8.6 million for the three months ended March 31, 2015 as compared to the prior year period. Excluding the effects of accrual estimates for the quarter ended March 31, 2014, our LOE increased by approximately $3.3 million in 2015. Contributing to the higher expense was higher workover expenses related to our production optimization efforts, particularly related to recently acquired producing properties in our East Texas business unit and our Powder River business unit. We expect workover expenses to occur less frequently for the remainder of 2015. Also contributing to the higher LOE in 2015 was additional compensation expense of $0.9 million related to cash based incentive compensation that was not present in 2014 and severance payments associated with the divestiture of our Arkoma assets in March 2015. Finally, the acquisition of producing properties in December 2014 in our East Texas business unit contributed approximately $2.1 million of additional LOE in 2015, including costs related to certain non-recurring workovers.

Production and ad valorem taxes. Production and ad valorem taxes decreased $8.5 million for the three months ended March 31, 2015 as compared to the prior year period. The decrease in expense for the three months ended March 31, 2015 resulted from lower oil and gas revenues during the period. On a per unit basis, for the three months ended March 31, 2015, production and ad valorem taxes decreased by $0.17 per Mcfe as compared to the prior year period primarily as a result of lower realized pricing.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense decreased $14.4 million for the three months ended March 31, 2015 as compared to the prior year period, due primarily to a reduction in our depletion base in 2015 compared to the prior year period and less production. The reduction in our depletion base occurred due to previous ceiling test impairments, a reduction of estimated future development costs associated with proved undeveloped reserves due to an overall reduction of proved undeveloped reserves, and proceeds received from divestitures of oil and gas properties.

Impairment of oil and gas properties. We recorded pre-tax impairment expense related to our oil and gas properties for the three months ended March 31, 2015 of $629.5 million 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 months ended March 31, 2015 were impairments of our unproved properties of approximately $98.9 million, as well as decreases in the value of our proved reserves used in our ceiling test calculation resulting primarily from reductions in required pricing used in the quarterly tests.

Related party management fee. We have an 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 agreement, the management fee increases 5% on an annual basis. The related party management fee increased $0.3 million for the three months ended March 31, 2015 as compared to the prior year period. As described in Note 16 to our condensed consolidated financial statements included in Part I, Item 1—“Financial Statements” of this report, our shareholders consented to an extension of time for the payment of this quarterly management fee.

Restructuring charges. Restructuring charges primarily relates to severance costs of $22.1 million incurred during the three months ended March 31, 2015 associated with a workforce reduction and corporate restructuring announced in March 2015. Also included in restructuring charges was an acceleration of expense recognition of $12.1 million associated with previous grants made under our incentive compensation plans to terminated employees and officers.

General and administrative expenses. The following table illustrates the changes in certain categories of general and administrative expenses for the periods presented:

 

		Three Months Ended March 31,
		2015				2014
Cash incentive compensation		$	2,552			$	—
Officer retention awards			7,260				—
Other stock based compensation			13,636				9,814
Professional fees associated with debt restructuring			4,823				—
Other general and administrative expenses			30,587				31,166
Total general and administrative expenses		$	58,858			$	40,980

 

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Cash incentive compensation increased due to the granting of awards beginning in April 2014 and an acceleration of vesting of certain awards that occurred on September 1, 2014. There was no expense recorded for the officer retention awards during the three months ended March, 31 2014, as the officer retention awards were approved in the third quarter of 2014. The increase in other stock based compensation primarily relates to higher expense associated with restricted stock, which increased by approximately $7.3 million. The increase resulted from new grants of restricted stock that occurred in March 2014 and an acceleration of vesting of all restricted stock beginning in September 2014. The increase in restricted stock expense was offset by decreases in stock compensation expense related to stock options as 2014 included additional expense resulting from modifications to the exercise price of unexercised stock options which occurred in the first quarter of 2014. In the first quarter of 2015, we incurred approximately $4.8 million of legal and other consulting costs associated with our debt restructuring activities and other strategic initiatives.

Interest expense. Interest expense was $64.1 million and $20.5 million for the three months ended March 31, 2015 and 2014, respectively. We capitalized interest costs to unproved oil and gas properties of $34.8 million and $63.6 million during the three months ended March 31, 2015 and 2014, respectively. Total interest cost before capitalization was $98.9 million and $84.1 million for the three months ended March 31, 2015 and 2014, respectively. The increase in total interest cost for the three month period ended March 31, 2015 was primarily due to the write off of approximately $15.1 million of unamortized deferred costs resulting from the March 2015 amendment to the credit agreement governing the RBL Revolver, which reduced the total commitment level to $950.0 million from $2.25 billion.

Income tax provision. Income tax benefit was $271.6 million and $0.4 million for the three months ended March 31, 2015 and 2014, respectively. The change in the income tax benefit is due to the difference in pre-tax loss between the periods. The effective income tax rate for the three months ended March 31, 2015 and 2014 was approximately 36% and 31%, respectively. Realization of our deferred tax assets is dependent upon generating sufficient future taxable income and also considers the reversing effects of our deferred tax liabilities.

Liquidity and Capital Resources

The following table summarizes factors affecting our liquidity at March 31, 2015 and December 31, 2014 (in thousands):

 

		At March 31, 2015				At December 31, 2014
Cash and cash equivalents		$	194,056			$	23,826
Net working capital, including debt classified as current		$	(4,139,168	)		$	(4,030,296	)
Net working capital, excluding debt classified as current		$	57,832			$	(125,296	)
Cumulative preferred stock subject to mandatory redemption		$	206,865			$	202,808
Available borrowing capacity under RBL Revolver		$	—			$	343,384

Short-term liquidity

We have historically funded our operations with operating cash flow, borrowings under our various credit facilities, and asset sales. Our most significant cash outlays relate to our capital program, current period operating expenses, payments under various incentive plans, severance related costs, and our debt service obligations described in Notes 10, 11, 12 and 14 in the accompanying condensed consolidated financial statements included in Part I, Item 1—“Financial Statements” of this report.

The market price for oil, natural gas and NGLs decreased significantly during the fourth quarter of 2014 with continued weakness into 2015. The decrease in the market price for our production directly reduces our revenues and operating cash flow. We use derivative financial instruments to reduce our exposure to fluctuations in the prices of oil, natural gas and NGLs. The following table summarizes our hedging position associated with our estimated remaining 2015 and 2016 production as of March 31, 2015:

 

		Percent of estimated 2015 production hedged								Weighted average hedged price for existing hedges
		2015				2016				2015				2016
Oil			30	%			—			$	90.91/Bbl			$	—
Natural gas			58	%			60	%		$	4.04/MMBtu			$	4.04/MMBtu
NGLs			7	%			—			$	37.07/Bbl			$	—

Our hedging program will reduce the potential effects of lower cash flows from operations due to decreases in product prices on the portion of production hedged. We do not anticipate entering into new hedges unless market prices increase from current levels.

 

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In addition, the decrease in the market price for our production indirectly impacts our other sources of potential liquidity described above. Lower market prices for our production may result in lower borrowing capacity under our revolving credit facility or higher borrowing costs from other potential sources of debt financing as our borrowing capacity and borrowing costs are generally related to the value of our estimated proved reserves. The weakness in product pricing may also impact our ability to negotiate asset sales at acceptable prices.

We also have substantial debt service obligations over the next several months. In addition to monthly interest payments associated with borrowings outstanding on our RBL Revolver, we are required to pay approximately $110.0 million in interest on our Senior Notes on each February 15 and August 15 and approximately $12.5 million in interest on our Second Lien Term Loan at the end of each fiscal quarter.

In addition, declining industry conditions and company performance reduces the likelihood that we comply with certain restrictive covenants contained in our credit facilities, which potentially can have severe consequences to our liquidity. Violation of certain restrictive covenants can result in costly waivers or amendments to agreements governing our credit facilities or an acceleration of repayment obligations for outstanding borrowings. In March 2015, we amended the credit agreement governing the RBL Revolver to, among other things, modify the financial performance covenant to provide that we maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 2.75 to 1.0 as of the end of each fiscal quarter beginning with the first quarter of 2015 through and including the third quarter of 2015. The consolidated first lien debt to consolidated EBITDA ratio reverts back to 1.5 to 1.0 at the end of the fourth quarter of 2015. Beginning with the first quarter of 2016, the credit agreement requires us to maintain a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 as of the end of each fiscal quarter through maturity. In addition, the March 2015 amendment added a restrictive covenant requiring us to maintain, subsequent to July 1, 2015, minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due in 2020 and the Second Lien Term Loan and waived the restriction on the inclusion of an explanatory paragraph regarding our ability to continue as a going concern in our auditor’s report for 2014. In addition, the March 2015 amendment lowered the borrowing base of our RBL Revolver to $950.0 million and we used $46.0 million of cash on hand to repay amounts outstanding on the RBL Revolver on the amendment date. The March 2015 amendment also increased the collateral coverage minimum (as defined in the credit agreement) to at least 95% of the discounted present value of our restricted subsidiaries proved reserves.

Unless the financial performance and/or the liquidity covenants are amended further, or we are successful in implementing one of the strategic alternatives discussed below, we do not expect to remain in compliance with all of our restrictive covenants contained in agreements governing our credit facilities for all of 2015 or 2016. Consequently, an acceleration of repayments of outstanding borrowings may occur. As a result of the uncertainty regarding our compliance with our restrictive covenants, our long-term debt with maturities summarized in Note 10 to our condensed consolidated financial statements are reflected as a current liability in our condensed consolidated balance sheet at March 31, 2015. If an acceleration of repayments of outstanding borrowings were to occur, we may not have access to funding sources sufficient to repay our outstanding obligations. Conditions that are considered an event of default that may result in an acceleration of maturities under our various credit agreements are listed in our 2014 Annual Report on Form 10-K.

We have begun implementing plans designed to improve our liquidity. We have reduced our 2015 capital budget, developed plans to reduce long-term recurring operating expenses, disposed of properties associated with the Arkoma Basin in Oklahoma and have completed necessary preparation to sell additional certain non-core assets in the event market conditions improve. However, the terms of the RBL Revolver, our Second Lien Term Loan and the indenture governing our Senior Notes require that some or all of the proceeds from certain asset sales be used to permanently reduce outstanding debt which could substantially reduce the amount of proceeds we retain. The covenants in the RBL Revolver, our Second Lien Term Loan and indenture governing our Senior Notes impose limitations on the amount and type of additional indebtedness we can incur, which may significantly reduce our ability to obtain liquidity through the incurrence of additional indebtedness. Additionally, our ability to refinance any of our existing indebtedness on commercially reasonable terms may be materially and adversely impacted by the current conditions in the energy industry and our financial condition.

Even if we are successful at reducing our costs and increasing our liquidity through asset sales, we do not expect to have sufficient liquidity to satisfy our debt service obligations, meet other financial obligations, and comply with restrictive covenants contained in our various credit facilities. We have engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring. However, a filing under Chapter 11 of the U.S. Bankruptcy Code may provide the most expeditious manner in which to effect a capital structure solution. There can be no assurance that we will be able to restructure our capital structure on terms acceptable to us or our financial creditors, or at all.

 

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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.

Net Working Capital

Net working capital is the difference between our current assets and our current liabilities. At March 31, 2015, our net working capital deficit, including debt classified as current, was $(4.1) billion. Our most significant current assets include cash on hand of $194.1 million, accounts receivable of $147.6 million, and net derivative assets of $117.3 million. Our accounts receivable balance includes outstanding joint interest billings to other working interest owners in wells we operate and an accrual for our share of revenue associated with product sales that occurred prior to March 31, 2015. The value of our derivative assets are based on the forward market prices for oil, natural gas and NGLs at March 31, 2015. Actual cash settlements will be more or less than the value of our derivative assets at period end based on changes in the market value of oil, natural gas and NGLs through the settlement date of the derivative financial instruments.

At March 31, 2015, our net working capital deficit includes an amount of current liabilities of $4.2 billion associated with our long-term debt with maturities summarized in Note 10 to our condensed consolidated financial statements. Our long-term debt is classified as current at March 31, 2015 due to uncertainty regarding our compliance with certain restrictive covenants contained in our credit facilities. Our other significant current liabilities include accounts payable of $96.2 million and accrued liabilities of $213.7 million. Accounts payable represents the amount of invoices we have processed for payment as of a particular date. Accrued liabilities represent an accrual for expenses or capital expenditures incurred as of a particular date which is not reflected in accounts payable. Our most significant items included in accrued liabilities relate to accrued operating expenses, accrued capital expenditures, accrued long-term incentive payments and other employee retention programs, and accrued interest associated with outstanding borrowings under our RBL Revolver, Second Lien Term Loans, and Senior Notes.

We have also implemented procedures to manage our available cash. During the quarter ended March 31, 2015, we borrowed the maximum amount from our RBL Revolver, which increased the amount of cash on hand and borrowings outstanding under our RBL Revolver. We have also increased the time period between when our costs are incurred and when payments to our vendors are made.

Debt

At March 31, 2015, total outstanding debt was approximately $4.2 billion, which excludes approximately $206.9 million of our Cumulative Preferred Stock. Our total debt consists of three separate financing arrangements: the RBL Revolver, which at March 31, 2015, had a total borrowing capacity of approximately $950.0 million and outstanding borrowings of $947.0 million, excluding letters of credit; 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. The maturities, interest costs, expected interest payments, and restrictive covenants associated with all of our debt is summarized in Note 10 to our condensed consolidated financial statements included in Part I, Item 1—“Financial Statements” of this report.

In March 2015, we amended the credit agreement governing the RBL Revolver to, among other things, modify the financial performance covenant to provide that we maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 2.75 to 1.0 as of the end of each fiscal quarter beginning with the first quarter of 2015 through and including the third quarter of 2015, at which point the first lien debt to consolidated EBITDA ratio reverts back to 1.5 to 1.0 at the end of the fourth quarter of 2015 and beginning with the first quarter of 2016, we are required to maintain a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 as of the end of each fiscal quarter through maturity. In addition, the March 2015 amendment added a restrictive covenant requiring us to maintain minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due 2020 and the Second Lien Term Loan and waived the inclusion of an explanatory paragraph regarding our ability to continue as a going concern in our auditor’s report for 2014. In addition, the March 2015 amendment lowered the borrowing base of our RBL Revolver to $950.0 million and we used $46.0 million of cash on hand to repay amounts outstanding on the RBL Revolver on the amendment date. The March 2015 amendment also increased the collateral coverage minimum (as defined in the credit agreement) to at least 95% of the discounted present value of our restricted subsidiaries proved reserves.

 

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As described above, the financial performance covenant in the credit agreement governing the RBL Revolver requires us to operate within established financial ratios. In addition, the March 2015 amendment to the credit agreement governing the RBL Revolver requires us to maintain a certain liquidity on the date of certain interest payments made subsequent to July 1, 2015. Our ability to comply with these covenants depends upon our performance and indebtedness, each of which is impacted by numerous factors, including some that are outside of our control. Accordingly, forecasting our compliance with the financial performance and liquidity covenants in future periods is inherently uncertain. Factors that could impact our future compliance with the financial performance and liquidity covenants include future production, returns generated by our capital program, future interest costs, future operating costs, future asset sales and future acquisitions, among others. For example, asset sales could impact our near-term future performance by reducing our production and reserves and, for purposes of calculating compliance with the financial performance covenant, could reduce our consolidated EBITDA on a pro forma historical basis. Moreover, many of these factors could also decrease our total proved reserves and thereby may result in a reduction to our borrowing base under the RBL Revolver, which could adversely impact our liquidity and ability to meet future obligations.

Unless the financial performance covenant and/or the liquidity covenants are amended further, we do not expect to remain in compliance with all of our restrictive covenants contained in the credit agreement governing the RBL Revolver for all of 2015 or into 2016. Collectively, the negative impacts to our liquidity resulting from declining industry conditions and increased uncertainty regarding our ability to comply with restrictive covenants in our credit facilities raises substantial doubt about our ability to continue as a going concern as of March 31, 2015 as described in Note 1 to our condensed consolidated financial statements included in Part I, Item 1—“Financial Statements” of this report.

As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we, our affiliates and/or our equity investors and their respective affiliates, may from time to time seek to repurchase our outstanding debt, including the Senior Notes and Second Lien Term Loan debt, in open market transactions or privately negotiated transactions, by tender offer or otherwise. The amounts involved in any such transactions, individually or in the aggregate, may be material. Further, any such repurchases may result in our acquiring and retiring a substantial amount of such indebtedness, which would impact the trading liquidity of such indebtedness.

Cumulative Preferred Stock Subject to Mandatory Redemption

Our preferred stock is recorded at its redemption value. The preferred stock is redeemable at our option at any time and is mandatorily redeemable on the earliest to occur of July 1, 2022, or the consummation of an initial public equity offering or a change of control.

Contractual Obligations

Our contractual obligations include long-term debt, interest expense on debt, drilling commitments, derivatives, the Cumulative Preferred Stock, officer retention agreements, cash incentive awards, operating lease obligations, related party management fee, marketing commitments and non-cancelable equipment purchases. There were no material changes in our contractual obligations at March 31, 2015 as compared to December 31, 2014, other than those disclosed in Notes 10 and 14 to the condensed consolidated financial statements.

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 and letters of credit as described in Note 14 to the condensed consolidated financial statements.

Capital Expenditures

Total capital expenditures, including capitalized direct internal costs and interest paid, were approximately $202.9 million for the three months ended March 31, 2015. Substantially all of our expenditures, excluding 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.

 

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Due to the significant decline in commodity prices and our evaluation of our short-term liquidity, we decided to discontinue drilling and completion activity after the first quarter of 2015 and adopt a 2015 capital budget that is much lower than recent spending levels. The following table summarizes our capital budget for the year ended December 31, 2015, excluding capitalized direct internal costs and interest paid (in thousands):

 

		2015 Capital Budget
Drilling and completion:
West Division		$	52,500
East Division			40,700
Total drilling and completion			93,200
Leasehold, geological and geophysical			11,500
Related field facilities, corporate and other			51,800
Total capital budget, excluding capitalized direct internal costs and interest paid (1)		$	156,500

 

(1)	Amount does not include capital related to our 2014 capital program that was incurred in 2014 expected to be paid in the first and second quarters of 2015 of approximately $100.0 million to $110.0 million.

The following table sets forth information regarding capital expenditures for the three months ended March 31, 2015 (in thousands):

 

Drilling and completion		$	82,844
Tubular oil and gas equipment, prepaid drilling costs and other			22,810
Total drilling and completion			105,654
Leasehold, geological and geophysical			3,018
Related field facilities, corporate and other			7,794
Total			116,466
Capitalized interest paid			79,884
Capitalized direct internal costs			6,504
Total capital expenditures		$	202,854

A substantial percentage of our capital expenditures paid in the first quarter of 2015 relate to capital incurred in 2014 related to our 2014 capital program.

We primarily fund our capital expenditures with our cash flows generated by operations, borrowings under our RBL Revolver or Second Lien Term Loans, and proceeds from asset sales. 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 adjusting or reallocating our capital spending plans.

 

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Sources and Uses of Cash

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

 

		Three Months Ended March 31,
		2015				2014
Operating activities		$	20,472			$	103,203
Investing activities			(142,242	)			(263,096	)
Financing activities			292,000				159,810
Net change in cash		$	170,230			$	(83	)

Cash flows from operating activities. Cash flows from operating activities decreased $82.7 million for the three months ended March 31, 2015 as compared to the prior year period. The decrease in cash flows from operating activities was primarily the result of a decrease in our net income (loss) adjusted for certain non-cash items of $142.5 million offset by increases to our cash flows from changes to our operating assets and liabilities of $59.7 million. The primary reason for the decrease in our net income adjusted for certain non-cash items was a decrease in oil, natural gas and NGL sales of $160.5 million as compared to the three months ended March 31, 2014. The decrease in product revenues relates primarily to decreases in realized prices in 2015 compared to 2014. The non-cash items primarily relate to full cost ceiling impairment expense, non-cash derivative gains, stock compensation expense, depletion and depreciation expense, non-cash interest expense and deferred taxes. The increase in cash flows resulting from changes to our operating assets and liabilities was primarily the result of cash inflows in 2015 from the change in our accounts receivable and accounts payable balances of $55.4 million compared with cash outflows of $66.5 million in 2014. The accounts receivable balances in 2015 were impacted by decreases in product prices and collections of billed receivables. The accounts payable balances increased due to a new cash management process that was implemented during 2015 to extend the time between when costs are incurred and when payments are made to our vendors. The increase in cash flows from operating activities was offset by net cash outflows related to undistributed revenue and accrued and other current liabilities of $41.8 million in 2015 compared to net cash inflows of $5.2 million in 2014. The change in undistributed revenue relates to decreased product pricing in 2015 compared with earlier periods. The change in accrued and other current liabilities was impacted primarily by interest payments that were classified as operating activities in 2015 and investing activities in 2014, as we capitalized less interest cost associated with our oil and gas activities.

Cash flows used in investing activities. Cash flows used in investing activities decreased $120.9 million for the three months ended March 31, 2015 as compared to the prior year period. Contributing to the decrease was a decrease in capital expenditures for oil and gas properties and other property and equipment of $65.7 million resulting from a lower 2015 capital budget. Also contributing to the decrease was an increase in proceeds from divestitures of oil and gas properties of $54.6 million as compared to the three months ended March 31, 2014 primarily related to the Arkoma divestiture in March 2015.

Cash flows from financing activities. Cash flows from financing activities increased $132.2 million for the three months ended March 31, 2015 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 under the RBL Revolver of $130.0 million as compared to the three months ended March 31, 2014. 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 16 to the condensed consolidated financial statements.

Critical Accounting Policies

There were no changes in our critical accounting policies and estimates from December 31, 2014. 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 our 2014 Annual Report.

 

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Recent Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-03 “Interest-Imputation of Interest.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years for public entities. Early adoption is permitted. The Company is evaluating the impact of this guidance, which will be adopted beginning with the Company’s quarterly report for the period ending March 31, 2016.

In August 2014, the FASB issued ASU 2014-15 “Presentation of Financial Statements—Going Concern.” ASU 2014-15 provides guidance regarding management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for our annual period ending after December 15, 2016, and for all annual and interim periods thereafter. Early application is permitted. We have not determined when we will adopt ASU 2014-15 or the impact the new standard will have on our consolidated financial statements. Upon adoption, we will be required to consider whether there are adverse conditions or events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued. Adverse conditions or events would include, but not be limited to, negative financial trends, a need to restructure outstanding debt to avoid default, and industry developments.

In May 2014, the 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. In April 2015, the FASB voted to propose to defer the effective date by one year. Early adoption is permitted. We are currently evaluating the potential impact of ASU 2014-09 on our consolidated financial statements.

 

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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, natural gas and NGL 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. All of our market risk sensitive instruments were entered into for risk mitigation purposes, rather than for speculative trading.

At March 31, 2015, we had open natural gas derivatives, crude oil and NGL derivatives in an asset position with a combined fair value of $159.5 million. A ten percent increase in natural gas, crude oil and NGL prices would decrease the asset position by approximately $38.0 million. See Note 8 to our condensed consolidated financial statements for notional volumes and terms associated with the Company’s derivative contracts.

Interest Rate Risk

Under our RBL Revolver and Second Lien Term Loan, we have debt which bears interest at a floating rate. For the three months ended March 31, 2015, the weighted average interest rates on our RBL Revolver and Second Lien Term Loan were 3.2% 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 $4.9 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.

 

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ITEM 4. CONTROLS AND PROCEDURES

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 March 31, 2015. 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. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2015 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting. In March 2015, we announced a corporate reorganization and a workforce reduction of approximately 35% of our employees. The workforce reduction resulted in necessary changes to our system of internal controls as certain employees are performing control activities that they were not performing prior to the workforce reduction. We expect continued changes in our system of internal controls as we align our control structure with our current workforce. Except for the aforementioned changes, 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 March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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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 currently 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 14 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 our 2014 Annual Report. 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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

 

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ITEM 6. EXHIBITS

 

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File No.

Exhibit

Filing Date

Filed Herewith *

10.1

Fifth Amendment and Waiver 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 March 18, 2015.

10-K

333-186686

10.6

3/31/2015

—

10.2

Form of Samson Resources Corporation 2015 Performance Bonus Plan.

10-K

333-186686

10.51

3/31/2015

—

10.3

Form of Bonus Award.

10-K

333-186686

10.52

3/31/2015

—

10.4

Form of Performance Award.

10-K

333-186686

10.53

3/31/2015

—

10.5

Form of Samson Resources Corporation 2015 Bonus Plan.

10-K

333-186686

10.54

3/31/2015

—

10.6

Form of Settlement, Waiver and Release Agreement.

10-K

333-186686

10.55

3/31/2015

—

10.7

Form of Release Payment.

10-K

333-186686

10.56

3/31/2015

—

31.1

Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated May 15, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

31.2

Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated May 15, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

32.1

Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated May 15, 2015, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

X

32.2

Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated May 15, 2015, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

X

101.INS

XBRL Instance Document.

X

101.SCH

XBRL Taxonomy Schema Document.

X

101.CAL

XBRL Calculation Linkbase Document.

X

101.LAB

XBRL Label Linkbase Document.

X

 

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Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File No.

Exhibit

Filing Date

Filed Herewith *

101.PRE

XBRL Presentation Linkbase Document.

X

101.DEF

XBRL Definition Linkbase Document.

X

 

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

 

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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 May 15, 2015.

 

 

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INDEX TO EXHIBITS

 

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File No.

Exhibit

Filing Date

Filed Herewith *

10.1

Fifth Amendment and Waiver 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 March 18, 2015.

10-K

333-186686

10.6

3/31/2015

—

10.2

Form of Samson Resources Corporation 2015 Performance Bonus Plan.

10-K

333-186686

10.51

3/31/2015

—

10.3

Form of Bonus Award.

10-K

333-186686

10.52

3/31/2015

—

10.4

Form of Performance Award.

10-K

333-186686

10.53

3/31/2015

—

10.5

Form of Samson Resources Corporation 2015 Bonus Plan.

10-K

333-186686

10.54

3/31/2015

—

10.6

Form of Settlement, Waiver and Release Agreement.

10-K

333-186686

10.55

3/31/2015

—

10.7

Form of Release Payment.

10-K

333-186686

10.56

3/31/2015

—

31.1

Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated May 15, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

31.2

Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated May 15, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

32.1

Certification of Randy L. Limbacher, Director, Chief Executive Officer and President (Principal Executive Officer), dated May 15, 2015, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

X

32.2

Certification of Philip W. Cook, Executive Vice President and Chief Financial Officer (Principal Financial Officer), dated May 15, 2015, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

X

101.INS

XBRL Instance Document.

X

101.SCH

XBRL Taxonomy Schema Document.

X

101.CAL

XBRL Calculation Linkbase Document.

X

101.LAB

XBRL Label Linkbase Document.

X

 

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Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File No.

Exhibit

Filing Date

Filed Herewith *

101.PRE

XBRL Presentation Linkbase Document.

X

101.DEF

XBRL Definition Linkbase Document.

X

 

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

 

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