WARREN RESOURCES INC - FORM 10-Q

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended June 30, 2014

o 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. 000-33275

WARREN RESOURCES, INC.

(Exact Name of Registrant as Specified in its Charter.)

Maryland
(State or other jurisdiction of
incorporation or organization)

11-3024080
(I.R.S. Employer
Identification Number)

1114 Avenue of the Americas,

New York, NY
(Address of Principal Executive Offices)

10036
(Zip Code)

Registrant’s telephone number, including area code:

(212) 697-9660

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 and 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer o

Accelerated filer x

Non-accelerated filer o

Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

The aggregate number of Registrant’s outstanding shares on August 8, 2014 was 73,893,826 shares of Common Stock, $0.0001 par value.

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WARREN RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

PART I—	FINANCIAL INFORMATION

	Item 1. Financial Statements (Unaudited)

	Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013

	Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013

	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2014 and 2013

	Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013

	Notes to the Consolidated Financial Statements

	Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations

	Item 3. Quantitative and Qualitative Disclosures About Market Risk

	Item 4. Controls and Procedures

PART II—	OTHER INFORMATION

	Item 1. Legal Proceedings

	Item 1A. Risk Factors

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

	Item 3. Defaults upon Senior Securities

	Item 4. Mine Safety Disclosures

	Item 5. Other Information

	Item 6. Exhibits

	Signatures

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PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WARREN RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	June 30, 2014 (Unaudited)			December 31, 2013
	(in thousands, except share and per share data)
ASSETS
Current Assets
Cash and cash equivalents	$	1,754		$	11,620
Accounts receivable — trade	15,107			21,874
Restricted investments in U.S. Treasury Bonds—available for sale, at fair value	138			131
Other current assets	2,370			1,859

Total current assets	19,369			35.484

Other Assets
Oil and gas properties—at cost, based on full cost method of accounting, net of accumulated depreciation, depletion and amortization (includes unproved properties excluded from amortization of $18,179 and $18,015 as of June 30, 2014 and December 31, 2013)	357,119			335,354
Property and equipment—at cost, net	18,790			18,772
Restricted investments in U.S. Treasury Bonds—available for sale, at fair value	1,242			1,183
Other assets	3,879			3,969
Derivative financial instruments	14			43

Total other assets	381,044			359,321
	$	400,413		$	394,805
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current maturities of debentures and other long-term liabilities	$	1,663		$	1,936
Accounts payable and accruals	36,864			39,174
Derivative financial instruments	2,872			3,517

Total current liabilities	41,399			44,627

Long-Term Liabilities
Revolving Loan Credit Facility	81,500			94,500
Other long-term liabilities, less current portion	29,799			28,113
Debentures, less current portion	1,472			1,472

	112,771			124,085
Commitments and Contingencies

Stockholders’ Equity
8% convertible preferred stock, par value $.0001; authorized 10,000,000 shares, issued and outstanding, 10,703 shares in 2014 and 2013 (aggregate liquidation preference $128 in 2014 and 2013)	128			128
Common stock — $.0001 par value; authorized, 100,000,000 shares; issued 73,684,750 shares in 2014 and 72,887,650 shares in 2013	7			7
Additional paid-in-capital	471,606			470,441
Accumulated deficit	(225,708		)	(244,673		)
Accumulated other comprehensive income, net of applicable income taxes of $138 in 2014 and $124 in 2013	210			190

Total stockholders’ equity	246,243			226,093
	$	400,413		$	394,805

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

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WARREN RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended June 30, (Unaudited)						Six Months Ended June 30, (Unaudited)
	(in thousands, except share						(in thousands, except share
	and per share data)						and per share data)
	2014			2013			2014			2013
Operating revenues
Oil and gas sales	$	33,572		$	30,735		$	66,451		$	61,554
Transportation revenue	1,422			—			2,745			—

Total revenues	34,994			30,735			69,196			61,554

Operating expenses
Lease operating expense and taxes	9,208			8,330			18,710			18,126
Depreciation, depletion and amortization	10,535			11,810			20,889			23,381
Transportation expense	551			—			1,116			—
General and administrative	3,867			3,930			7,833			8,247


Total operating expenses	24,161			24,070			48,548			49,754

Income from operations	10,833			6,665			20,648			11,800

Other income (expense)
Interest and other income	2,228			16			2,362			31
Interest expense	(645		)	(724		)	(1,399		)	(1,474		)
Gain (loss) on derivative financial instruments	(1,668		)	3,260			(2,661		)	1,695

Total other income (expense)	(85		)	2,552			(1,698		)	252

Income before taxes	10,748			9,217			18,950			12,052

Deferred income tax expense (benefit)	(6		)	32			(14		)	39

Net income	10,754			9,185			18,964			12,013

Less dividends and accretion on preferred shares	2			2			5			5

Net income applicable to common stockholders	$	10,752		$	9,183		$	18,959		$	12,008

Earnings per share — Basic	$	0.15		$	0.13		$	0.26		$	0.17
Earnings per share — Diluted	0.15			0.13			0.26			0.17

Weighted average common shares outstanding — Basic	73,651,858			72,283,896			73,379,507			72,138,686
Weighted average common shares outstanding — Diluted	73,904,104			72,852,877			73,558,350			72,723,453

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

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WARREN RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended June 30, (Unaudited)					Six Months Ended June 30, (Unaudited)
	(in thousands, except share					(in thousands, except share
	and per share data)					and per share data)
	2014		2013			2014		2013
Net income	$	10,754	$	9,185		$	18,964	$	12,013
Other comprehensive income
Gain (loss) on investments held for sale	9		(49		)	20		(60		)

Comprehensive income	$	10,763	$	9,136		$	18,984	$	11,953

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

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WARREN RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the six months ended June 30, (Unaudited)
	(in thousands)
	2014			2013

Cash flows from operating activities:
Net income	$	18,964		$	12,013
Adjustments to reconcile net income to net cash provided by operating activities:
Accretion of discount on available-for-sale debt securities	(32		)	(30		)
Amortization of deferred offering costs	113			106
Depreciation, depletion and amortization	20,889			23,381
Change in fair value of derivative financial instruments	(617		)	(2,156		)
Stock option expense	1,069			945
Deferred tax (benefit) expense	(14		)	39
Change in assets and liabilities:
Decrease (increase) in accounts receivable—trade	6,767			(1,489		)
Increase in other assets	(510		)	(869		)
(Decrease) increase in accounts payable and accruals	(7,018		)	1,666
Decrease in other long-term liabilities	(260		)	(1,194		)

Net cash provided by operating activities	39,351			32,412

Cash flows from investing activities:
Purchase, exploration and development of oil and gas properties	(35,312		)	(22,113		)
Purchase of property and equipment	(982		)	(1,766		)

Net cash used in investing activities	(36,294		)	(23,879		)

Cash flows from financing activities:
Proceeds from line of credit	14,500			—
Payments on debt and debentures	(27,525		)	(10,017		)
Proceeds from the exercise of stock options	102			361

Net cash used in financing activities	(12,923		)	(9,656		)

Net decrease in cash and cash equivalents	(9,866		)	(1,123		)

Cash and cash equivalents at beginning of period	11,620			8,475

Cash and cash equivalents at end of period	$	1,754		$	7,352

Supplemental disclosure of cash flow information
Cash paid for interest, net of amounts capitalized	$	1,335		$	1,347
Noncash investing and financing activities
Accrued preferred stock dividend	5			5

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

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WARREN RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE A—ORGANIZATION

Warren Resources, Inc. (the “Company” or “Warren”), was originally formed on June 12, 1990 for the purpose of acquiring and developing oil and gas properties. The Company is incorporated under the laws of the state of Maryland. The Company’s properties are primarily located in California and Wyoming.

The accompanying unaudited financial statements and related notes present the Company’s consolidated financial position as of June 30, 2014 and December 31, 2013, the consolidated results of operations for the three and six months ended June 30, 2014 and 2013, the consolidated statements of comprehensive income for the three and six months ended June 30, 2014 and 2013 and consolidated cash flows for the six months ended June 30, 2014 and 2013. The unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the six months ended June 30, 2014 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2014. The accounting policies followed by the Company are set forth in Note A to the Company’s financial statements included in Form 10-K for the year ended December 31, 2013. These interim financial statements and notes thereto should be read in conjunction with the consolidated financial statements presented in the Company’s 2013 Annual Report on Form 10-K.

NOTE B—STOCK BASED COMPENSATION

Stock Options

Compensation expense related to stock options and restricted stock awards recognized in operating results (general and administrative expenses) was approximately $0.5 and $0.6 million for the three months ended June 30, 2014 and June 30, 2013, respectively, and approximately $1.1 and $0.9 million for the six months ending June 30, 2014 and June 30, 2013, respectively.

The following assumptions were used to value stock options calculated using the Black-Scholes options pricing model:

	Six months ended June 30,
	2014		2013
Dividend yield	0	%	0	%
Expected volatility	52.8	%	70.9	%
Risk-free interest rate	1.0	%	0.5	%
Expected life	3.5 years		3.5 years

			Weighted		Weighted
			Average		Average	Aggregate
	Number		Exercise		Remaining	Intrinsic Value
	of Options		Price		Term (in years)	(in thousands)
Outstanding at March 31, 2014	1,485,321		$	3.35
Granted	290,810		4.84
Exercised	(59,949	)	2.66
Forfeited or expired	(5,000	)	2.75
Outstanding at June 30, 2014	1,711,182		$	3.63	3.63	$	4,398
Exercisable at June 30, 2014	525,239		$	2.86	1.93	$	1,755

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The total intrinsic value of options exercised during the six months ended June 30, 2014 and 2013 were approximately $1.0 million and $461,000 respectively.

As of June 30, 2014 total unrecognized stock-based compensation expense related to non-vested stock options was approximately $2.0 million, which we expect to recognize over a weighted average period of 1.9 years.

Restricted Shares

Restricted share activity for the six months ended June 30, 2014 was as follows:

	Shares		Weighted Average Fair Value

Outstanding at December 31, 2013	1,898,133		$	1.97
Granted	225,296		4.62
Vested	(511,527	)	2.81
Forfeited	(25,399	)	2.89
Outstanding at June 30, 2014	1,586,503		$	2.06

Restricted stock awards for executive officers and employees generally vest ratably over three years. Fair value of our restricted shares is based on our closing stock price on the date of grant. As of June 30, 2014, total unrecognized stock-based compensation expense related to non-vested restricted shares was $2.8 million, which is expected to be recognized over a weighted average period of approximately 1.3 years.

NOTE C—STOCKHOLDERS’ EQUITY

The preferred stock pays an 8% cumulative dividend which is treated as a deduction of additional paid in capital, due to insufficient retained earnings. The holders of the preferred stock are not entitled to vote except as defined by the agreement or as provided by applicable law. The preferred stock may be voluntarily converted, at the election of the holder, into common stock of the Company based on a conversion rate of one share of preferred stock for 0.50 shares of common stock. The accrual of the dividend is deducted from earnings in the calculation of earnings attributable to common stockholders.

Additionally, holders of the preferred stock can elect to require the Company to redeem their preferred stock at a redemption price equal to the liquidation value of $12.00 per share, plus accrued but unpaid dividends, if any, (“Redemption Price”). Upon the receipt of a redemption election, the Company, at its option, shall either: (1) pay the holder cash in the amount equal to the Redemption Price or (2) issue to the holder shares of common stock in an amount equal to 125% of the redemption price and any accrued and unpaid dividends, based on the weighted average closing “bid” price of the Company’s common stock for the thirty trading days immediately preceding the date of the written redemption election by the holder up to a maximum of 1.5 shares of common stock for each one share of preferred stock redeemed. The Company has accreted the carrying value of its preferred stock to its redemption price using the effective interest method with changes recorded to additional paid in capital. The accretion of preferred stock results in a reduction of earnings applicable to common stockholders.

Notwithstanding the forgoing, if the closing “bid” price of the Company’s publicly traded common stock as reported by the NASDAQ stock market, or any exchange on which the shares of common stock are traded, exceeds 133% of the conversion price then in effect for the convertible preferred shares for at least 10 days during any 30-day trading period, the Company has the right to redeem in whole or in part the convertible preferred stock at a redemption price of $12 per share (plus any accrued unpaid dividends) or convert the convertible preferred shares (plus any accrued unpaid dividends) into common stock at the then applicable conversion rate.

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NOTE D—EARNINGS PER SHARE

Basic earnings per share is computed by dividing net earnings applicable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is based on the assumption that stock options are converted into common shares using the treasury stock method and convertible bonds and preferred stock are converted using the if-converted method. Conversion is not assumed if the results are anti-dilutive. Potential common shares for the six months ended June 30, 2014 and 2013 of 38,072 and 38,072, respectively, relating to convertible bonds and preferred stock were excluded from the computation of diluted earnings per share because they are anti-dilutive. Potential common shares of 2,392,313 and 2,794,021 relating to stock options and restricted stock were excluded from the computation of diluted earnings per share for the six months ended June 30, 2014 and 2013, respectively, because they are anti-dilutive. At June 30, 2014 the convertible bonds may be converted from the date of issuance until maturity at 100% of principal amount into common stock of the Company at a price of $50. The preferred stock may be converted at the discretion of the holder or upon meeting certain conditions at the discretion of the Company (see Note C).

Basic and diluted net earnings per share are computed based on the following information:

	Three Months Ended June 30, 2014		Three Months Ended June 30, 2013		Six Months Ended June 30, 2014		Six Months Ended June 30, 2013
	(in thousands, except for per share data)				(in thousands, except for per share data)

Net earnings applicable to common shareholders	$	10,752	$	9,183	$	18,959	$	12,008

Weighted average shares outstanding — basic	73,651,858		72,283,896		73,379,507		72,138,686
Effect of dilutive securities — restricted stock	—		11,822		—		15,592
Effect of dilutive securities — stock options	252,246		557,159		178,843		569,175

Weighted average shares outstanding - diluted	73,904,104		72,852,877		73,558,350		72,723,453

Basic net earnings per share	$	0.15	$	0.13	$	0.26	$	0.17
Diluted net earnings per share	$	0.15	$	0.13	$	0.26	$	0.17

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NOTE E—LONG-TERM LIABILITIES

Long-term liabilities, excluding derivative financial instruments (see Note I), consisted of the following for the balance sheets dated:

	June 30,		December 31,
	2014		2013
	(in thousands)

Line of Credit	$	81,500	$	94,500
Convertible debentures	1,636		1,636
Asset retirement obligations	28,198		26,785
Litigation allowance	3,100		3,100
	114,434		126,021
Less current portion	1,663		1,936
Long-term portion	$	112,771	$	124,085

On December 15, 2011, the Company entered into a five-year $300 million Second Amended and Restated Credit Agreement with Bank of Montreal. The Credit Facility provides for a revolving credit facility up to the lesser of: (i) $300 million, (ii) the Borrowing Base, or (iii) the Draw Limit requested by the Company. The Credit Facility matures on December 15, 2016, is secured by substantially all of Warren’s oil and gas assets, and is guaranteed by the two wholly-owned subsidiaries of the Company. In May 2014, the borrowing base was increased to $175 million. The maximum amount available is subject to semi-annual redeterminations of the borrowing base in April and October of each year, based on the value of the Company’s proved oil and natural gas reserves in accordance with the lenders’ customary procedures and practices. Both the Company and the lenders have the right to request one additional redetermination each year. Credit line interest of approximately $121,000 was accrued as of June 30, 2014. As of June 30, 2014 the Company has $81.5 million outstanding on its borrowing base.

The Company is subject to certain covenants under the terms of the Credit Facility which include, but are not limited to, the maintenance of the following financial ratios (1) minimum current ratio of current assets (including unused borrowing base in current assets) to current liabilities of 1.0 to 1.0 and (2) a minimum annualized consolidated EBITDAX (as defined by the Credit Facility) to net interest expense of 2.5 to 1.0. The Company is in compliance with all covenants as of June 30, 2014.

Depending on the amount outstanding and the level of borrowing base usage, the annual interest rate on each base rate loan under the Credit Facility will be, at the Company’s option, either: (a) a “LIBOR Loan”, which has an interest rate equal to the sum of the applicable LIBOR period plus the applicable “LIBOR Margin” that ranges from 1.75% to 2.75%, or (b) a “Base Rate Loan”, or any other obligation other than a LIBOR Loan, which has an interest rate equal to the sum of the “Base Rate”, calculated to be the higher of: (i) the Agent’s prime rate of interest announced from time to time, or (ii) the Federal Funds rate most recently determined by the Agent plus one-half percent, plus an applicable “Base Rate Margin” that ranges from 0.75% to 1.75%. The weighted average interest rate as of June 30, 2014, was 2.41%.

The convertible bonds may be converted from the date of issuance until maturity at 100% of principal amount into common stock of the Company at a conversion price of $50. Each year the holders of the convertible bonds may tender to the Company up to 10% of the aggregate bonds issued and outstanding. During the three months ended June 30, 2014, there were no bond redemptions.

NOTE F—ASSET RETIREMENT OBLIGATION

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method. The associated liability is classified in other long-term liabilities, net of current portion, in the accompanying Consolidated Balance Sheets. The liability is

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periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization. The Company has cash held in escrow with a fair market value of $3.2 million that is legally restricted for potential plugging and abandonment liability in the Wilmington field which is recorded in other assets in the Consolidated Balance Sheets. A reconciliation of the Company’s asset retirement obligations is as follows:

	June 30, 2014
	(in thousands)
Balance at beginning of period	$	26,785
Liabilities incurred in current period	431
Liabilities settled in current period	(260		)
Accretion expense	1,242
Balance at end of period	$	28,198

NOTE G—CONTINGENCIES

The following information should be read in conjunction with the discussion set forth under Part I, Item 3. “Legal Proceedings” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

In 2005, Warren recorded a provision for $1.8 million relating to a contingent liability that the Company may face as a result of a lawsuit originally filed in 1998 by Gotham Insurance Company (‘‘Gotham’’) in the 81st Judicial District Court of Frio County, Texas (Gotham Insurance Company v. Pedeco, Inc., et al.,) seeking a refund of approximately $1.8 million paid by Gotham and other insurers under an insurance policy issued for a well blow-out that occurred in 1997. After several appeals to the Texas Court of Appeals and the Texas Supreme Court, the case was remanded to the trial court for further proceedings. Both parties filed Motions for Summary Judgment in mid-2009, and on November 19, 2009, the trial court heard oral arguments on both Motions for Summary Judgment. On January 22, 2010 the trial court awarded Gotham $1,823,156 and also awarded prejudgment interest at the rate of 5% per annum in the amount of $976,011. As a result of the January 2010 Summary Judgment, Warren recorded an additional provision of $1.3 million in the fourth quarter of 2009 relating to this contingent liability. On July 7, 2010, Warren E&P posted a supersedeas bond with the court and commenced to appeal the order of the trial court to the Texas Court of Appeals. The San Antonio Court of Appeals assigned and transferred this appeal to the El Paso Court of Appeals. On March 14, 2011, Warren filed its appellate brief with the El Paso Court of Appeals. The El Paso Court of Appeals held oral arguments of the case on January 12, 2012. On April 18, 2012, the Texas Court of Appeals reversed the judgment of the trial court and rendered its appellate decision in favor of Warren ruling that Gotham Insurance take nothing against Warren. Additionally, the Texas Court of Appeals ordered that Warren can recover all costs of the appeal from Gotham Insurance. In response to the April 18, 2012 ruling, on June 4, 2012, Gotham filed a petition with the Texas Supreme Court seeking a review of the ruling. On September 26, 2012, Warren filed a reply brief in opposition to Gotham’s petition. The Court asked for further briefing and on December 18, 2012 Gotham filed a brief on the merits of their appeal. On February 6, 2013, Warren filed its brief in response to Gotham’s brief. On April 19, 2013, the Supreme Court granted Gotham’s petition for a review of the Court of Appeals ruling. The Court held oral arguments on the merits of the appeal on October 8, 2013 and, on March 21, 2014, ordered that the case be remanded to the Court of Appeals for reconsideration on the merits of Gotham’s potential contractual claims for reimbursement. On April 7, 2014, Gotham filed a motion for rehearing asking the Court to reconsider its ruling. On June 20, 2014, the Court denied Gotham’s motion for rehearing and issued a mandate returning the case to the El Paso Court of Appeals. On July 15, 2014, the case was returned to the El Paso Court of Appeals.

We are party to a variety of legal, administrative, regulatory and government proceedings, claims and inquiries arising in the normal course of business. While the results of these proceedings, claims and inquiries cannot be predicted with certainty, management believes that the ultimate outcome of such matters will not have a material effect on the Company’s financial condition or results of operations. See “Item 1. Business — Regulation and Environmental Matters” and “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

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NOTE H - FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of financial instruments recognized in the Consolidated Balance Sheets or disclosed within these Notes to Consolidated Financial Statements have been determined using available market information, information from unrelated third party financial institutions and appropriate valuation methodologies, primarily discounted projected cash flows. However, considerable judgment is required when interpreting market information and other data to develop estimates of fair value.

Short-term Assets and Liabilities. The fair values of cash and cash equivalents, accounts receivable, accounts payable and accrued expenses and other current liabilities approximate their carrying values because of their short-term nature.

U.S. Treasury Bonds - Trading and Available-For-Sale Securities. The fair values are based upon quoted market prices for those or similar investments and are reported on the Consolidated Balance Sheets at fair value.

Collateral Security Agreement Account (included in other non-current assets). The balance sheet carrying amount approximates fair value, as it earns a market rate.

Convertible Debentures. Fair values of fixed rate convertible debentures were calculated using interest rates in effect as of period end for similar instruments with the other terms unchanged.

Other Long-Term Liabilities. The carrying amount approximates fair value due to the current rates offered to the Company for long-term liabilities of the same remaining maturities.

Line of Credit. The carrying amount approximates fair value due to the current rates offered to the Company for lines of credit.

Derivatives. The fair values are based upon observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs) and are reported on the Consolidated Balance Sheets at fair value

	June 30, 2014				December 31, 2013
	Fair		Carrying		Fair		Carrying
	value		amount		value		amount
	(in thousands)
Financial assets
Collateral security account	$	3,164	$	3,164	$	3,166	$	3,166
Financial liabilities
Fixed rate debentures	$	2,885	$	1,636	$	2,035	$	1,636
Line of credit	81,500		81,500		94,500		94,500

FAIR VALUE MEASUREMENTS:

Fair value as defined by authoritative literature is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three level hierarchy for measuring fair value. The literature requires fair value measurements be classified and disclosed in one of the following categories:

Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

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Level 2: Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.

Level 3: Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

The following tables present for each hierarchy level our assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis.

June 30, 2014

	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Restricted investments in US Treasury Bonds — available for sale, at fair value	$	1,380	$	—	$	—	$	1,380
Commodity derivatives	—		14		—		14

	Level 1		Level 2		Level 3		Total
	(in thousands)
Liabilities
Commodity derivatives	$	—	$	2,872	$	—	$	2,872

December 31, 2013

	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Restricted investments in US Treasury Bonds — available for sale, at fair value	$	1,314	$	—	$	—	$	1,314
Commodity derivatives	—		43		—		43

	Level 1		Level 2		Level 3		Total
	(in thousands)
Liabilities
Commodity derivatives	$	—	$	3,517	$	—	$	3,517

NOTE I — DERIVATIVE FINANCIAL INSTRUMENTS

To minimize the effect of a downturn in oil and gas prices and protect our profitability and the economics of our development plans, we enter into crude oil and natural gas hedge contracts. The terms of contracts depend on various factors, including management’s view of future crude oil and natural gas prices. This price hedging program is designed to moderate the effects of a crude oil and natural gas price downturn while allowing us to participate in some commodity price increases. Management regularly monitors the crude oil and natural gas markets and our financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging and/or basis adjustments or other price protection is appropriate. However, we may use a variety of derivative instruments in the future to hedge. The Company has not designated these derivatives as hedges for accounting purposes

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The Company routinely enters into derivative contracts with a variety of counterparties, typically resulting in individual derivative instruments with both fair value asset and liability positions. The Company nets the fair values of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which mitigate the credit risk of the Company’s derivative instruments by providing for net settlement over the term of the contract and in the event of default or termination of the contract.

The following table summarizes the open financial derivative positions, as of June 30, 2014, related to oil and gas production. The Company will receive prices as noted in the table below and will pay a counterparty market price based on the NYMEX (for natural gas production) or both BRENT and NYMEX (for oil production) index price, settled monthly.

Product	Type	Contract Period	Volume	Price per Mcf or Bbl
BRENT Oil	Swap	07/01/14 - 12/31/14	800 Bbl/d	$	102.12
BRENT Oil	Swap	07/01/14 - 09/30/14	700 Bbl/d	$	104.30
NYMEX Oil	Swap	10/01/14 - 12/31/14	300 Bbl/d	$	101.67
NYMEX Gas	Swap	07/01/14 - 12/31/14	7,000 MMBtu/d	$	3.79
NYMEX Gas	Swap	07/01/14 - 12/31/14	2,000 MMBtu/d	$	4.18
NYMEX Gas	Swap	07/01/14 - 12/31/14	3,000 MMBtu/d	$	4.27
NYMEX Gas	Swap	01/01/15 - 12/31/15	3,000 MMBtu/d	$	4.18
NYMEX Gas	Swap	07/01/14 - 12/31/14	6,000 MMBtu/d	$	0.20	*

*This represents a differential spread between NYMEX and CIG pricing.

The tables below summarize the amount of gains (losses) recognized in income from derivative instruments not designated as hedging instruments under authoritative guidance.

Derivatives not designated as	For the Three Months						For the Six Months
Hedging Instrument under	Ended June 30,						Ended June 30,
authoritative guidance	2014			2013			2014			2013
(in thousands)
Realized cash settlements on hedges	$	(1,477	)	$	(509	)	$	(3,278	)	$	(677	)
Unrealized gain (loss) on hedges	(191		)	3,769			617			2,372

Total	$	(1,668	)	$	3,260		$	(2,661	)	$	1,695

The table below reflects the line item in our Consolidated Balance Sheet where the fair value of our net derivatives, are included.

June 30, 2014

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June 30, 2014

	Derivative Liabilities
(in thousands)	Balance Sheet Location	Fair Value
Commodity—Oil	current	$	(1,829	)
Commodity—Natural Gas	current	(1,043		)

Total derivatives not designated as hedging instruments		$	(2,872	)

December 31, 2013

December 31, 2013

	Derivative Liabilities
(in thousands)	Balance Sheet Location	Fair Value
Commodity—Oil	current	$	(2,709	)
Commodity—Natural Gas	current	(808		)

Total derivatives not designated as hedging instruments		$	(3,517	)

Derivatives Credit Risk

The Company does not require collateral or other security from counterparties to support derivative instruments. However, the agreements with those counterparties typically contain netting provisions such that if a default occurs, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contract with the amount due from the defaulting party. As a result of the netting provisions the Company’s maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts.

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As of June 30, 2014, the counterparties to the Company’s commodity derivative contracts consisted of two financial institutions which are also lenders under the Company’s Senior Credit Agreement and share in the collateral supporting the Agreement. The Company is not generally required to post additional collateral under derivative agreements.

The Company’s derivative agreements contain provisions that require cross defaults and acceleration of those instruments to any material debt. If the Company were to default on any of its material debt agreements, it would be a violation of these provisions, and the counterparties to the derivative instruments could request immediate payment on derivative instruments that are in a net liability position at that time

NOTE J — INCOME TAXES

The Company’s effective tax rate differs from the federal statutory tax rate due to changes in the valuation allowance on the Company’s net deferred tax asset.

NOTE K — RECENTLY ISSUED ACCOUNTING STANDARDS

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company is currently evaluating the impact of adopting ASU 2014-09, but the standard is not expected to have a significant effect on its consolidated financial statements.

NOTE L — RECENT DEVELOPMENTS

On July 7, 2014, we agreed to acquire essentially all of the Marcellus assets (the ‘‘Marcellus Assets’’) of Citrus Energy Corporation (‘‘Citrus’’) and two other working interest owners in exchange for approximately 6.7 million shares of our common stock valued at $40 million and cash consideration of $312.5 million, subject to certain post-closing adjustments and certain closing conditions (the ‘‘Citrus Acquisition’’). The Citrus Acquisition will provide us a new area of operations in the Marcellus Shale in Pennsylvania in addition to our existing California and Wyoming assets. We completed the Citrus Acquisition on August 11, 2014.

In addition, we entered into a five-year, Third Amended and Restated Credit Agreement with Bank of Montreal, as Administrative Agent (the “Amended Credit Facility”) in connection with the Citrus Acquisition on August 11, 2014, which provides for a maximum credit amount of $750 million and an initial borrowing base of $225 million. Other than the maximum credit amount and the initial borrowing base, the terms of our Amended Credit Facility are substantially similar to the terms of our Existing Credit Facility.

Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic

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performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, and those statements preceded by, followed by or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the Company’s assumptions about energy markets, production levels, reserve levels, operating results, competitive conditions, technology, the availability of capital resources, capital expenditures and other contractual obligations, the supply and demand for and the price of oil, natural gas and other products or services, the weather, inflation, the availability of goods and services, drilling risks, future processing volumes and pipeline throughput, general economic conditions, either internationally or nationally or in the jurisdictions in which the Company or its subsidiaries are doing business, legislative or regulatory changes, including changes in environmental regulation, environmental risks and liability under federal, state and local environmental laws and regulations, potential environmental obligations, the securities or capital markets, our ability to repay debt and other factors discussed in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Company’s 2013 Annual Report on Form 10-K, this Form 10-Q, and in the Company’s other public filings, press releases and discussions with Company management. Warren undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, subsequent events or otherwise, unless otherwise required by law.

Overview

We are an independent energy company engaged in the exploration and development of domestic onshore oil and natural gas reserves. We focus our efforts primarily on our waterflood oil recovery programs and horizontal drilling in the Wilmington field within the Los Angeles Basin of California and on the exploration and development of coalbed methane (“CBM”) properties located in the Rocky Mountain region. As of June 30, 2014, we owned oil and natural gas leasehold interests in approximately 122,500 gross, 91,900 net acres, approximately 75% of which are undeveloped. Substantially all our undeveloped acreage is located in the Rocky Mountains.

Liquidity and Capital Resources

Our cash and cash equivalents decreased approximately $9.9 million to $1.8 million during the six months ended June 30, 2014. This resulted from cash provided from operating activities of $39.4 million being offset by cash used in investing activities of $36.3 million and cash used in financing activities of $12.9 million.

Cash provided by operating activities was primarily generated by oil operations. Cash used in investing activities was primarily spent on capital expenditures for the development of oil and gas properties and the purchase of property and equipment. Cash used in financing activities primarily represents the payments on our line of credit during the period.

Capital expenditures for the six months ended June 30, 2014 were approximately $40 million and consisted of $32.7 million for drilling and development in our California properties and $7.2 million for development in our Wyoming properties.

In May 2014, the borrowing base under our Second Amended and Restated Credit Agreement described in Note E to our Consolidated Financial Statements (the “Credit Facility”) was increased to $175 million.

During the six months ended June 30, 2014, the Company incurred $1.2 million of interest expense under the Credit Facility of which approximately $121,000 was accrued as of June 30, 2014. The weighted average interest rate as of June 30, 2014 was 2.41% and the total amount outstanding under the Credit Facility as that date was $81.5 million.

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In addition, we entered into a five-year, Third Amended and Restated Credit Agreement with Bank of Montreal, as Administrative Agent (the “Amended Credit Facility”) simultaneously with the Citrus Acquisition, which provides for a maximum credit amount of $750 million and an initial borrowing base of $225 million. Other than the maximum credit amount and the initial borrowing base, the terms of our Amended Credit Facility are substantially similar to the terms of our Existing Credit Facility.

During the first six months of 2014, the Company had net income of $19.0 million (which included $2.7 million of losses on derivative financial instruments). This compares to the first six months of 2013 when the Company had net income of $12 million (which included $1.7 million of gains on derivative financial instruments). At June 30, 2014, current assets were $22.0 million less than current liabilities.

At June 30, 2014, we had approximately 1.7 million outstanding stock options issued under our stock based equity compensation plans. Of the total outstanding vested options, none had exercise prices above the closing market price of $6.20 of our common stock on June 30, 2014.

Contractual Obligations

The contractual obligations table below assumes the maximum amount under contract is tendered each year. The table does not give effect to the conversion of any bonds to common stock which would reduce payments due. All bonds are secured at maturity by zero coupon U.S. treasury bonds deposited into an escrow account equaling the par value of the bonds maturing on or before the maturity of the bonds. Such U.S. treasury bonds had a fair market value of $1.4 million at June 30, 2014. The table below does not reflect the release of escrowed U.S. treasury bonds to us upon redemption

	Payments due by period *
Contractual Obligations As of June 30, 2014	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
	(in thousands)

Line of credit	$	81,500	$	—	$	81,500	$	—	$	—
Bonds	1,636		164		280		226		966
Derivatives	2,872		2,872		—		—		—
Leases	6,036		766		1,544		1,605		2,121
Total	$	92,044	$	3,802	$	83,324	$	1,831	$	3,087

* Does not include estimated interest of $2.6 million less than one year, $4 million 1-3 years, $0.4 million 3-5 years and $0.5 million thereafter.

RESULTS OF OPERATIONS:

Three months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

Oil and gas sales. Revenue from oil and gas sales increased $2.8 million in the second quarter of 2014 to $33.6 million, a 9% increase compared to the same quarter in 2013. This increase primarily resulted from an increase in oil production and oil pricing. Net oil production for the three months ended June 30, 2014 and 2013 was 281 Mbbls and 262 Mbbls, respectively. Additionally, the average realized price per barrel of oil for the three months ended June 30, 2014 and 2013 was $97.59 and $95.60, respectively. Net gas production for the three months ended June 30, 2014 and 2013 was 1.63

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Bcf and 1.59 Bcf, respectively. The average realized price per Mcf of gas for the three months ended June 30, 2014 and 2013 was $3.76 and $3.60, respectively.

Transportation Revenue. We receive fees for transporting first-party gas through our Atlantic Rim intrastate gas pipeline, which connects with the Wyoming Interstate Company (“WIC”) pipeline system. Commencing in November 2013, we changed the point of sale for our Atlantic Rim gas, which allows us to recognize revenue for the transportation fee we charge. Transportation and gathering revenue totaled $1.4 million for the three months ended June 30, 2014.

Lease operating expense. Lease operating expense increased 11% to $9.2 million ($16.67 per Boe) for the second quarter of 2014 compared to $8.3 million ($15.81 per Boe) in the comparable period of 2013. Primarily, this increase resulted from increased workover expense in the Atlantic Rim.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense decreased $1.3 million for the second quarter of 2014 to $10.5 million, an 11% decrease compared to the corresponding quarter last year. This decrease reflects an increase in estimated proved reserves at 2013 year end, which resulted in the calculation of a lower overall depletion rate for 2014 compared to 2013. The 2014 depletion rate decreased to $19.07 per Boe compared to $22.42 per Boe in 2013.

Transportation Expense. Commencing in November 2013, we changed the point of sale for our Atlantic Rim gas which allows us to recognize revenue and the associated expense of operating our pipeline. Pipeline operating expenses totaled $0.6 million for the three months ended June 30, 2014.

General and administrative expenses. General and administrative expenses decreased $0.1 million in the second quarter of 2014 to $3.9 million, a 2% decrease compared to the same quarter last year. This decrease reflects lower salary and overhead expense resulting from the departure of several higher paid individuals during 2013.

Interest expense. Interest expense decreased $0.1 million to $0.6 million in the second quarter of 2014 compared to the same quarter last year. The decrease results from a decrease in borrowings under our Credit Facility from $89.5 million at June 30, 2013 to $81.5 million at June 30, 2014.

Interest and other income. Interest and other income increased $2.2 million in the second quarter of 2014 to $2.2 million, compared to the same quarter in 2013. This resulted from a retroactive adjustment relating to certain post-production costs being charged to royalty owners in the Wilmington Townlot Unit field.

Gain (loss) on derivative financial instruments. Derivative losses of $1.7 million were recorded during the second quarter of 2014. This amount reflects $1.5 million of realized losses and $0.2 million of unrealized losses resulting from mark to market accounting of our oil and gas swaps and future contract positions.

RESULTS OF OPERATIONS:

Six months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Oil and gas sales. Revenue from oil and gas sales increased $4.9 million in the first six months of 2014 to $66.5 million, an 8% increase compared to the same period in 2013. This increase primarily resulted from an increase in oil production and gas pricing. Net oil production for the six months ended June 30, 2014 and 2013 was 557 Mbbls and 518 Mbbls, respectively. Additionally, the average realized price per barrel of oil for the six months ended June 30, 2014 and 2013 was $96.26 and $98.25, respectively. Net gas production for the six months ended June 30, 2014 and 2013 was 3.22 Bcf and 3.13 Bcf, respectively. The average realized price per Mcf of gas for the six months ended June 30, 2014 and 2013 was $3.97 and $3.40, respectively.

Transportation Revenue. We receive fees for transporting first-party gas through our Atlantic Rim intrastate gas pipeline, which connects with the Wyoming Interstate Company (“WIC”) pipeline system. Commencing in November 2013, we changed the point of sale for our Atlantic Rim gas, which allows us to recognize revenue for the transportation fee we charge. Transportation and gathering revenue totaled $2.7 million for the six months ended June 30, 2014.

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Lease operating expense. Lease operating expense increased 3% to $18.7 million ($17.08 per boe) for the first six months of 2014 compared to $18.1 million ($17.43 per boe) in the comparable period of 2013. Primarily, this increase resulted from increased workover and fuel expense in the Atlantic Rim.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense decreased $2.5 million for the six months ended June 2014 to $20.9 million, an 11% decrease compared to the corresponding quarter last year. This decrease reflects an increase in estimated proved reserves at 2013 year end, which resulted in the calculation of a lower overall depletion rate for 2014 compared to 2013. The 2014 depletion rate decreased to $19.07 per boe compared to $22.49 per boe in 2013.

Transportation Expense. Commencing in November 2013, we changed the point of sale for our Atlantic Rim gas which allows us to recognize revenue and the associated expense of operating our pipeline. Pipeline operating expenses totaled $1.1 million for the six months ended June 30, 2014.

General and administrative expenses. General and administrative expenses decreased $0.4 million for the first six months of 2014 to $7.8 million, a 5% decrease compared to the same period last year. This decrease reflects lower salary and overhead expense resulting from the departure of several higher paid individuals during 2013.

Interest expense. Interest expense decreased $0.1 million to $1.4 million in the first six months of 2014 compared to the same period last year. The decrease results from a decrease in borrowings under our Credit Facility for the first six months of 2014 compared to the same period in 2013.

Interest and other income. Interest and other income increased $2.3 million in the first six months of 2014 to $2.4 million, compared to the same period last year. This resulted from a retroactive adjustment relating to certain post-production costs being charged to royalty owners in the Wilmington Townlot Unit field.

Gain (loss) on derivative financial instruments. Derivative losses of $2.7 million were recorded during the first six months of 2014. This amount reflects $3.3 million of realized losses and $0.6 million of unrealized gains resulting from mark to market accounting of our oil and gas swaps and future contract positions.

CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements that have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our 2013 Form 10-K includes a discussion of our critical accounting policies.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Energy Price Risk

The Company’s most significant market risk is the pricing for natural gas and crude oil. Management expects energy prices to remain volatile and unpredictable. If energy prices decline significantly, revenues and cash flow would significantly decline.

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Commodity Risk

Our primary market risk exposure is in the price we receive for our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

Derivative Instruments and Hedging Activity

We have entered into several financial derivative swap contracts to hedge our exposure to commodity price risk associated with anticipated future oil and gas production. We believe we will have more predictability of our crude oil and gas revenues as a result of these financial derivative contracts. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge up to at least 50% of our current and anticipated production for the next 12 to 24 months. Our hedge policies and objectives may change significantly as commodities prices or price futures change.

We are exposed to market risk on our open derivative contracts of non-performance by our counterparties. We do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings. Each of the counterparties to our derivative contracts is a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement.

The following table summarizes our open financial derivative positions as of August 11, 2014, related to oil and gas production. The Company will receive prices as noted in the table below and will pay a counterparty market price based on the NYMEX (for natural gas production) or both BRENT and NYMEX (for oil production) index price, settled monthly.

Product	Type	Contract Period	Volume	Price per Mcf or Bbl
BRENT Oil	Swap	07/01/14 - 12/31/14	800 Bbl/d	$	102.12
BRENT Oil	Swap	07/01/14 - 09/30/14	700 Bbl/d	$	104.30
NYMEX Oil	Swap	10/01/14 - 12/31/14	300 Bbl/d	$	101.67
NYMEX Gas	Swap	07/01/14 - 12/31/14	7,000 MMBtu/d	$	3.79
NYMEX Gas	Swap	07/01/14 - 12/31/14	2,000 MMBtu/d	$	4.18
NYMEX Gas	Swap	07/01/14 - 12/31/14	3,000 MMBtu/d	$	4.27
NYMEX Gas	Swap	01/01/15 - 12/31/15	3,000 MMBtu/d	$	4.18
NYMEX Gas	Swap	07/01/14 - 12/31/14	6,000 MMBtu/d	$	0.20	*

*This represents a differential spread between NYMEX and CIG pricing.

Interest Rate Risk

We are exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Depending on the amount outstanding and the level of borrowing base usage, the annual interest rate on each base rate loan under the Credit Facility will be, at the Company’s option, either: (a) a “LIBOR Loan”, which has an interest rate equal to the sum of the applicable LIBOR period plus the applicable “LIBOR Margin” that ranges from 1.75% to 2.75%, or (b) a “Base Rate Loan”, or any other obligation other than a LIBOR Loan, which has an interest rate equal to the sum of the “Base Rate”, calculated to be the higher of: (i) the Agent’s prime rate of interest announced from time to time, or (ii) the Federal Funds rate most recently determined by the Agent plus one-half percent, plus an applicable “Base Rate Margin” that ranges from 0.75% to 1.75%.

Other Financial Instruments

Other financial instruments consist of the following: cash and cash equivalents, U.S. treasury bonds, collateral security accounts, line of credit and other long-term liabilities. The carrying amounts of these instruments approximate fair market value due to the highly liquid nature of these short-term instruments or they are reported at fair value.

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Inflation and Changes in Commodity Prices

The general level of inflation affects our costs. Salaries and other general and administrative expenses are impacted by inflationary trends and the supply and demand of qualified professionals and professional services. Inflation and commodity price fluctuations affect the costs associated with exploring for and producing oil and natural gas, which have a material impact on our financial performance.

Forward-Looking Statements and Risk

Certain statements in this report, including statements of the future plans, objectives, and expected performance of the company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the company’s control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil and gas, economic and competitive conditions, exploration risks such as drilling unsuccessful wells, higher-than-expected costs, potential liability for remedial actions under existing or future environmental regulations and litigation, potential liability resulting from pending or future litigation, environmental and regulatory uncertainties that could delay or prevent drilling, and not successfully completing, or any material delay of, any development of new or existing fields, expansion, or capital expenditure, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict. Forward-looking statements are generally accompanied by words such as “estimate”, “project”, “predict”, “will”, “anticipate”, “plan”, “intend”, “believe”, “expect” or similar expressions that convey the uncertainty of future events or outcomes. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Warren does not undertake any obligation to update any forward-looking statements, as a result of new information, future events or otherwise. Certain risks that may affect Warren’s results of operations and financial position appear in Part 1, Item 1A “Risk Factors” of Warren’s 2013 Annual Report on Form 10-K and this Quarterly Report on Form 10-Q.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can affect these risks. Fluctuations in oil and natural gas prices or a prolonged continuation of low prices may adversely affect the company’s financial position, results of operations and cash flows.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision and with the participation of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), has evaluated the effectiveness of our disclosure controls and procedures as defined in Securities and Exchange Commission (“SEC”) Rule 13a-15(e) and 15d-15(e) as of the end of the period covered by this report. Based upon that evaluation, management has concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act is communicated to management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal controls over financial reporting or in other factors during the quarter ended June 30, 2014, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Information with respect to this item may be found in Note G to the Consolidated Financial Statements (Part I, Item 1), which is incorporated herein by reference.

Item 1A. Risk Factors

Our business has many risks. In addition to the other information set forth in this report and our press releases and other reports and materials that we file with the Securities and Exchange Commission, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013 and this Quarterly Report on Form 10-Q, which could materially affect our business, financial condition, operating results or liquidity and the trading price of our common stock. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

Oil and natural gas prices are volatile. Volatility in oil and natural gas prices can adversely affect our results and the price of our notes. This volatility also makes valuation of oil and natural gas producing properties difficult and can disrupt markets.

Oil and natural gas prices have historically been, and are likely to continue to be, volatile. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. Some of the factors that cause these fluctuations are:

· demand for oil and natural gas, which is affected by worldwide population growth, economic development and general economic and business conditions;

· the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas from shale (such as that produced from the Marcellus Assets) on the global natural gas supply;

· political and economic uncertainty and socio-political unrest;

· the price and quality of foreign imports of oil and natural gas;

· political and economic conditions in oil and natural gas producing countries, especially the Middle East, Africa, Russia and South America;

· the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain oil price and production controls;

· the level of domestic and international exploration, drilling and production activity;

· the level of global inventories;

· the cost of exploring for, developing, producing and delivering oil and natural gas;

· the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil;

· weather conditions and changes in weather patterns;

· the price and availability of, and demand for, competing energy sources, including coal, liquefied natural gas, and alternative energy sources;

· the extent to which natural gas markets in the United States become integrated with global natural gas markets through the approval and development of infrastructure supporting the export of liquefied and other natural gas;

· technological advances affecting energy consumption and production;

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· the nature and extent of governmental regulation and taxation, including environmental regulations affecting competing energy sources as well as natural gas;

· risks associated with operating drilling rigs; and

· variations between product prices at sales points and applicable index prices.

· Additionally, continuance of the current lower natural gas price environment, further declines in natural gas prices and the lack of natural gas storage may have the following effects on our business:

· reduction of our revenues, operating income and cash flows;

· curtailment or shut-in of our natural gas production due to lack of transportation or storage capacity;

· cause certain of our properties to become economically unviable;

· cause material or significant reductions in our capital investment programs, resulting in a failure to develop our natural gas reserves; and

· limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations.

The long-term effects of these and other conditions on the prices of oil and natural gas are uncertain. Price volatility makes it difficult to budget and project the return on exploration and development projects involving our oil and natural gas properties and to estimate with precision the value of producing properties that we may own or propose to acquire. In addition, unusually volatile prices often disrupt the market for oil and natural gas properties as buyers and sellers have more difficulty agreeing on the purchase price of properties. Our cash flow and results of operations depend to a great extent on the prevailing prices for oil and natural gas. Our annual and quarterly results of operations may fluctuate significantly as a result of, among other things, variations in oil and natural gas prices and production performance. In recent years, oil and natural gas price volatility has become increasingly severe, and continuing volatility may have a material adverse effect on our future business, financial condition and results of operations.

In addition, among the assets that we are acquiring as part of the Citrus Acquisition is a natural gas supply agreement with a subsidiary of Procter and Gamble. During the year ended December 31, 2013 and the three months ended March 31, 2014, approximately 38% and 27.5%, respectively, of Citrus’ production was sold pursuant to this agreement. During these same periods, the prices that Citrus received for production under this contract generally were higher than the prices Citrus received for natural gas from other third parties. The customer has elected to terminate the agreement effective June 10, 2015. While we are in discussions with the customer to renew or extend the agreement, there can be no assurance that we will be successful in doing so or that the price secured under the contract will be advantageous compared to market pricing at the time of sale. If we are unable to renew or extend the agreement, or if we negotiate a price that is lower than what is ultimately available in the open market, our revenues may be unfavorably impacted.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Some of our completion activities involve, and upon closing the Citrus Acquisition, our operations in Pennsylvania will involve, the use of hydraulic fracturing, which is an important and common process that creates a fracture extending from the well bore in a rock formation to enable oil or natural gas to move more easily through the rock pores to a production well. Fractures are typically created through the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We will regularly use hydraulic fracturing as part of our operations in Pennsylvania. In California, our completion activities do not involve hydraulic fracturing, but do involve other technologies.

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Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies, however, legislative and regulatory efforts at the federal, state and local government level where we operate have been made to render permitting and compliance requirements more stringent for hydraulic fracturing and other technologies used to increase production. For example, the City of Los Angeles is currently considering whether to amend its zoning code to restrict or prohibit hydraulic fracturing and other completion activities. This and similar proposals, if adopted, would likely increase our costs and make it more difficult, or impossible, to pursue some of our development projects.

In addition, with increased public concern regarding the potential for hydraulic fracturing to adversely affect drinking water supplies, proposals have been made to enact federal, state and local legislation and regulations that would increase the regulatory burden imposed on hydraulic fracturing. For example, the U.S. Environmental Protection Agency, or the EPA, has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or SDWA, over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. The Safe Drinking Water Act regulates the underground injection of substances through the Underground Injection Control (“UIC”) program and exempts hydraulic fracturing from the definition of “underground injection”. However, Congress has from time to time considered legislation that would amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as require disclosure of the chemical constituents of the fluids used in the fracturing process. The U.S. Congress may consider similar SDWA legislation in the future.

In February 2014, the EPA asserted federal regulatory authority under the SDWA’s UIC program over hydraulic fracturing involving diesel additives, and requested comments in May 2014 on a proposal to require disclosure of chemical ingredients in hydraulic fracturing fluids under the Toxic Substances Control Act. Because the EPA’s Advanced Notice of Proposed Rulemaking did not propose any actual regulation, it is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations. Further, on October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations governing wastewater discharges from hydraulic fracturing and certain other natural gas operations, but has not yet proposed any such regulations. In addition, the U.S. Department of the Interior published a Supplemental Notice of Proposed Rulemaking on May 16, 2013 that would update existing regulation of hydraulic fracturing activities on federal and Indian lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. This proposed rulemaking is currently pending. Studies by the EPA and other federal agencies are underway that focus on the environmental aspects of hydraulic fracturing activities, with draft reports expected for public comment and peer review in late 2014. These studies could spur further regulation. Additional regulations adopted at the federal or state level could result in permitting delays and cost increases.

Along with several other states, Pennsylvania (where we will conduct operations upon closing the Citrus Acquisition) has adopted laws and proposed regulations that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. The chemical ingredient information is generally available to the public via online databases, and this may bring more public scrutiny to hydraulic fracturing operations. In addition, local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing, in particular. In Pennsylvania, although the legislature passed legislation to make regulation of drilling uniform throughout the state, the Pennsylvania Supreme Court in Robinson Township v. Commonwealth of Pennsylvania struck down portions of that legislation. Following this decision, local governments in Pennsylvania may adopt ordinances regulating drilling and hydraulic fracturing activities, especially within residential areas. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Proposed changes to U.S. and state tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

President Obama has made proposals that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil

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and natural gas exploration and production companies. Legislation has been introduced in Congress that would implement many of President Obama’s proposals. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production, and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition, results of operations and cash flows.

We could also be adversely affected by future changes to applicable state tax laws and regulations. For example, proposals have been made to amend California State and local laws to impose “windfall profits,” severance or other taxes on oil and natural gas companies. If any of these proposals become law, our costs would increase, possibly materially. Significant financial difficulties currently facing the State of California and other localities may increase the likelihood that one or more of these proposals will become law. For example, in California, there have been proposals at the legislative and executive levels over the past several years for tax increases which have included a severance tax as high as 12.5% on all oil production in California. Although the proposals have not passed the California Legislature, the financial crisis in the State of California could lead to a severance tax on oil being imposed in the future.

In February 2012, the state legislature of Pennsylvania passed a new natural gas impact fee. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. The fee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average NYMEX natural gas prices from the last day of each month. There can be no assurance that the impact fee will remain as currently structured or that new or additional taxes will not be imposed. In addition, there is currently no severance tax imposed on natural gas or oil in Pennsylvania. However, it is possible that a severance tax could be proposed and implemented in the coming years, which would negatively affect our future cash flows and financial condition.

Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.

Our oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing occupational health and safety aspects of our operations, the discharge of materials into the environment, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit before conducting drilling or other regulated activities; restriction of types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; application of specific health and safety criteria addressing worker protection; and imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations and due to historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with

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environmental laws and regulations or for personal injury or property or natural resource damages. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our business, financial condition or results of operations. Environmental advocacy groups and others continue to raise questions and concerns about potential environmental issues that may be associated with hydraulic fracturing, horizontal drilling, and related operations that are key aspects of our business, including concerns about potential impacts on groundwater quality, seismic activity, and greenhouse gas emissions; any of these could lead to changes in regulations in one or more of the jurisdictions in which we operate. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, or waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations in Pennsylvania upon closing of the Citrus Acquisition will involve utilizing some of the latest drilling and completion techniques as developed by us, other oil and gas exploration and production companies and our service providers. Risks that we face while drilling, including or as a result of the application of these techniques, include, but are not limited to, the following:

· effectively controlling the level of pressure flowing from particular wells;

· landing our wellbore in the desired drilling zone;

· staying in the desired drilling zone while drilling horizontally through the formation;

· running our casing the entire length of the wellbore; and

· being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells, including or as a result of the application of these techniques, include, but are not limited to, the following:

· the ability to fracture stimulate the planned number of stages;

· the ability to run tools the entire length of the wellbore during completion operations; and

· the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

Insufficient takeaway capacity in the Marcellus Shale could cause significant fluctuations in our realized natural gas prices.

The Marcellus Shale natural gas business environment has historically been characterized by periods in which production has surpassed local takeaway capacity, sometimes resulting in curtailment of production or substantial discounts in the price received by producers. We expect that a significant portion of our production in the Marcellus Shale will be transported on pipelines that experience a negative differential to NYMEX Henry Hub prices. Should production growth in the Marcellus Shale continue to outpace the increases in takeaway capacity or if we are unable to secure firm takeaway capacity to accommodate our growing production, it could result in substantial discounts in the price we receive for our production, may limit our ability to market our production and could have a material adverse effect on our financial condition and results of operations.

Acquired properties or businesses may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or businesses or obtain protection from sellers against them, which could cause us to incur losses.

One of our growth strategies is to pursue selective acquisitions of oil and natural gas reserves. We perform a review of the target properties that we believe is consistent with industry practices. However, these reviews may

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not be completely accurate. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable, even when an inspection is undertaken. Even when problems are identified, a seller may be unwilling or unable to provide effective contractual protection against all or part of those problems, and we often assume environmental and other risks and liabilities in connection with the properties we acquire.

In addition, any acquisition involves, among other things, the following potential risks:

· the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

· the risk of title defects discovered after closing;

· inaccurate assumptions about revenues and costs, including synergies;

· significant increases in our indebtedness and working capital requirements;

· an inability to transition and integrate successfully or timely the businesses we acquire;

· the cost of transition and integration of data systems and processes;

· the potential environmental problems and costs;

· the assumption of unknown liabilities;

· limitations on rights to indemnity from the seller;

· the diversion of management’s attention from other business concerns;

· increased demands on existing personnel and on our corporate structure;

· disputes arising out of acquisitions;

· customer or key employee losses of the acquired businesses; and

· the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, our future acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely impact our future growth and could have a material adverse effect on our business, financial condition and results of operations.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

a. Not applicable

b. Not applicable

c. Not applicable

Item 3. Defaults upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits

a) Exhibits

Exhibits not incorporated by reference to a prior filing are designated by an (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

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Exhibit
Number		Description

3.1(1)		Articles of Amendment to the Articles of Incorporation of Registrant

10.1(2)		Second Amendment to Credit Agreement, dated as of June 9, 2014, among Warren Resources, Inc., as Borrower, certain Subsidiaries of Borrower as Guarantors, Bank of Montreal, as Administrative Agent and as a Lender, the additional lenders that are parties thereto, and BMO Harris Financing, Inc., as the Swing Line Lender, amending the Second Amended and Restated Credit Agreement dated as of December 15, 2011, as amended.

31.1*		Certification of Chief Executive Officer pursuant to Rule 13a-15(e)/15d-15(e)

31.2*		Certification of Chief Financial Officer pursuant to Rule 13a-15(e)/15d-15(e)

32.1*		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002

32.2*		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002

101**		Interactive Data File.

*		Filed herewith.

**		Pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for the purposes of section 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities and Exchanges Act of 1934, as amended, and otherwise is not subject to liability under these sections.

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(1) Incorporated by reference to Exhibit A to the Company’s Definitive Proxy Statement on Form DEF 14-A filed on April 24, 2014.

(2) Incorporated by reference to the Company’s Current Report on Form 8-K, Commission File No. 000-33275, Filed June 10, 2014.

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.

	WARREN RESOURCES, INC.
	(Registrant)
Date: August 11, 2014

	By:	/s/ Stewart P. Skelly
		Stewart P. Skelly
		Vice President, Chief Financial Officer
		and Chief Accounting Officer

Derivative Assets

(in thousands)

Balance Sheet
Location

Fair Value

Commodity—Natural Gas

Non-current

Total derivatives not designated as hedging instruments