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WRES > SEC Filings for WRES > Form 10-K on 6-Mar-2013All Recent SEC Filings

Show all filings for WARREN RESOURCES INC



Annual Report

Item 7: Management's Discussion and Analysis of Financial Condition and Results of Operations

The discussion and analysis that follows should be read together with the "Selected Consolidated Financial Data" and the accompanying financial statements and notes related thereto that are included elsewhere in this annual report. It includes forward-looking statements that may reflect our estimates, beliefs, plans and expected performance. The forward-looking statements are based upon events, risks and uncertainties that may be outside our control. Our actual results could differ significantly from those discussed in these forward- looking statements. Factors that could cause or contribute to these differences include but are not limited to, market prices for natural gas and oil, regulatory changes, estimates of proved reserves, economic conditions, competitive conditions, development success rates, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this annual report, including in "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements", all of which are difficult to predict. As a result of these assumptions, risks and uncertainties, the forward-looking matters discussed may not occur.


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 December 31, 2012, we owned natural gas and oil leasehold interests in approximately 124,587 gross (94,140 net) acres, approximately 85% of which are undeveloped. Substantially all our undeveloped acreage is located in the Rocky Mountains. Our total net proved reserves are located on less than 15% of our net acreage.

From our inception in 1990 through 2003, we functioned principally as the sponsor of privately placed drilling programs and joint ventures. Under these programs, we contributed drilling locations, paid tangible drilling costs and provided turnkey drilling services. We also served as operator of these drilling programs and the Company retained an interest in the wells. Historically, a substantial portion of our revenue was attributable to these turnkey drilling services. After our initial public offering in 2004, the Company has transitioned from being the sponsor of privately placed drilling programs to becoming a more traditional exploration and production company. During the second quarter of 2007, the Company changed its accounting method for oil and gas properties from the successful efforts method to the full cost method. As a result of this accounting change, turnkey profit, well services profit and marketing profit are not recognized on the statement of operations but are recorded as reductions to the full cost pool. All historical information included in this Form 10-K has been retroactively restated to give effect to the change in accounting method.

Liquidity and Capital Resources

Our cash and cash equivalents decreased $2.1 million during 2012 to $8.5 million at December 31, 2012. This resulted from cash provided by operating activities of $66.8 million offset by cash used in investing activities of $79.7 million and cash provided by financing activities of $10.7 million.

Cash provided by operating activities was primarily generated by oil and gas operations. Cash used in investing activities was primarily spent on oil and gas properties and equipment. Cash provided by financing activities primarily represented an increase in net debt under the Credit Facility.

On December 15, 2011, the Company entered into a new, five-year $300 million Second Amended and Restated Credit Agreement with Bank of Montreal, as Administrative Agent (the "Agent"), and various other lenders named therein, and Warren Resources of California, Inc. and Warren E&P, Inc., as Guarantors (the "Credit Facility"). 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

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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 Guarantors, which are two wholly-owned subsidiaries of the Company. In December 2012, the borrowing base was increased to $140 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.

The Company is subject to various covenants required by the Credit Facility, including the maintenance of the following financial ratios: (1) a minimum current ratio of not less than 1.0 to 1.0 (including the unused borrowing base and excluding unrealized gains and losses on derivative financial instruments), and (2) a minimum annualized consolidated EBITDAX (as defined in the Credit Facility) to net interest expense of not less than 2.5 to 1.0.

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%. As of December 31, 2012, the Company had borrowed $99.5 million under the Credit Facility and was in compliance with all covenants. If oil and gas commodity prices were to decline to lower levels, the Company may become in violation of Credit Facility covenants in the future. If the Company fails to satisfy its Credit Facility covenants, it would be an event of default. Under such event of default and upon notice, all borrowings would become immediately due and payable to the lending banks. During 2012, the Company incurred $2.9 million of interest expense under the Credit Facility of which approximately $0.1 million was accrued for as of December 31, 2012. The weighted average interest rate as of December 31, 2012, was 2.5%.

Our operations are affected by local, national and worldwide economic conditions. We have relied on the capital markets, particularly for equity securities, as well as the banking and debt markets, to meet financial commitments and liquidity needs if internally generated cash flow from operations is not adequate to fund our capital requirements. Capital markets in the United States and elsewhere have been experiencing extreme adverse volatility and disruption, due in part to the financial stresses affecting the liquidity of the banking system, the real estate mortgage industry and the financial markets generally. Recently though, this volatility and disruption has been reduced.

If oil commodity prices were to drop precipitously and gas commodity prices stay the same or go lower, the Company may not have enough liquidity to cover capital expenditures. The availability of funds under our Credit Facility is critical to our Company. The borrowing base is to be redetermined on or about April 1, 2013. If the Credit Facility's borrowing base is reduced to a level below current borrowings, the Company would be obligated to begin reducing the deficiency by 25% within 90 days after the deficiency occurs and the remaining 75% within 180 days after the deficiency occurs.

Low commodity prices may restrict our ability to meet our current obligations. As a result, Management has taken several actions to ensure that the Company will have sufficient liquidity to meet its obligations through December 31, 2013, including a 2013 capital expenditure budget which is expected to be funded primarily by discretionary cash flow, entered into derivative agreements for a portion of its 2013 production to reduce price volatility and reductions in discretionary expenditures. As of February 1, 2013, approximately 43% of the Company's oil production is covered by put agreements. If the liquidity of the Company should worsen, the Company would evaluate other measures to further

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improve its liquidity, including, the sale of equity or debt securities, entering into joint ventures with third parties, additional commodity price hedging and other monetization of assets strategies. There is no assurance that the Company would be successful in these capital raising efforts if they became necessary to fund operations during 2013.

During 2012, the Company had net income of $15.5 million (of which $3.0 million represented a loss on derivative financial instruments). This compares to 2011 when the Company had net income of $21.6 million (of which $2.7 million represented a loss on derivative financial instruments) and a net income of $20.4 million in 2010 (of which $1.5 million represented a gain on derivative financial instruments). At December 31, 2012, current assets were approximately $3.6 million less than current liabilities. As of February 1, 2013, the Company has a borrowing base of $140 million and $99.5 million outstanding under the Credit Facility.

In the future, if natural gas inventories rise to levels such that no natural gas storage capacity exists, certain U.S. natural gas production will need to be reduced or shut in. Additionally, if commodity prices decline to levels that make it uneconomic to produce oil and natural gas, the Company or its partners may elect to shut in or reduce production. As a result, some or all of the Company's oil and natural gas production may be shut in or curtailed during the next 12 months, which would have a material adverse effect on operations.

The Company's proved reserves increased as of December 31, 2012 compared to prior years. The 2012 increase was primarily due to 2012 drilling activities and the acquisition of additional working interests in the Atlantic Rim. The Company's projects have material lease operating expenses. Our oil operations include a secondary recovery waterflood with significant fixed costs. During 2012, our oil lease operating expenses were $19.46 per barrel of oil produced. Our natural gas operations include reinjecting the produced water into deep formations and compressing and transporting the gas with significant fixed costs. During 2012, our natural gas lease operating expenses were $2.08 per Mcf of gas produced. The Company's proved reserves are based on assumptions that may prove to be inaccurate. The Company's proved reserves for the periods indicated are listed below.

                                                           Years Ended December 31,
                                                         2012        2011        2010
Estimated Proved Oil and Natural Gas Reserves:
Net oil reserves (MBbls)                                  16,380      14,963      10,250
Net natural gas reserves (MMcf)                           51,236      43,860      68,200

Total Net Proved Oil and Natural Gas Reserves (MBoe)      24,919      22,273      21,617

Estimated Present Value of Net Proved Reserves:
PV-10 Value (in thousands)
Proved developed                                       $ 337,786   $ 359,549   $ 245,306
Proved undeveloped                                       157,127     166,527      42,322

Total                                                    494,913     526,076     287,628
Less: future income taxes, discounted at 10%              35,033      40,070           -

Standardized measure of discounted future net cash
flows (in thousands)                                   $ 459,880   $ 486,006   $ 287,628

Prices Used in Calculating Reserves:
Oil (per Bbl)                                          $  104.27   $  104.75   $   73.30
Natural Gas (per Mcf)                                  $    2.51   $    3.21   $    4.13
Proved Developed Reserves (MBoe)                          16,603      13,101      15,735

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2012 Capital Expenditure Program

At the present time, we are concentrating our activities in California and Wyoming. We have two California projects in the Wilmington field, the Wilmington Townlot Unit and the North Wilmington Unit. Additionally, we have a drilling project in Wyoming referred to as the Atlantic Rim Project.

During 2012, our capital expenditure program approximated $46.2 million which included $15.7 million for our acquisition of certain Atlantic Rim properties. The Company drilled 18 wells in California (17 producers and 1 injector). The costs associated with the new oil wells in California wells were approximately $30.8 million and the facility costs were approximately $9.5 million. The Company did not drill any new wells in the Atlantic Rim Project in Wyoming.

If the Company elects not to participate in drilling activities with its partners, it may lose all or a portion of its mineral leases and rights in certain acreage. As a result, our proved reserves may decline. Also, unless we continue to develop our properties, production may decline and, as a result, reserves would decline. Lastly, complex federal, state and local laws and regulations may adversely affect the cost and feasibility of drilling and completion activities.

Based on the 2013 commodity price outlook and hedge positions, the Company forecasts a 2013 capital expenditure budget of approximately $57.9 million, consisting of $52.6 million for California oil drilling activities and $5.3 million for Wyoming. The Company may adjust its 2013 capital expenditures budget for Wyoming after it completes its evaluation of the deeper rights, including Niobrara oil potential and natural gas pricing. The amount and allocation of actual capital expenditures excludes capital expenditures for any acquisitions and will depend on a number of factors, including oil and gas prices, regulatory and environmental approvals, agreements among various working interest owners, drilling and service costs, timing of drilling wells, variances in forecasted production and acquisition opportunities. The above forecasted capital expenditures do not include acquisition capital. The Company intends to fund 2013 capital expenditures primarily with cash flow from operations.

During 2013, Warren plans to drill 3 Tar horizontal producers, 5 Upper Terminal sinusoidal producers, and 5 Ranger sinusoidal producers in the WTU. Additionally, Warren plans to drill 3 Ranger sinusoidal water injectors in the WTU. In the NWU, the Company plans to drill 4 sinusoidal producers in the Ranger formation and 3 sinusoidal injectors in 2013. The 2013 WTU capital budget consists of $28.1 for drilling and $5.3 million for facilities improvements and other infrastructure costs. Warren plans to spend approximately $11.6 million for drilling and $4.6 million on infrastructure improvements in the NWU in 2013. Additionally, the Company will be performing 3-D seismic mapping of the WTU and NWU geological formations at a budgeted cost of approximately $3.0 million. The Company plans to spend approximately $5.3 million in the Atlantic Rim project in 2013.

The final determination regarding whether to drill and complete the budgeted wells and incur the capital expenditures referred to above is dependent upon many factors including, but not limited to:

the availability of sufficient capital resources;

the ability to acquire proper governmental permits and approvals; and

economic and industry conditions at the time of drilling such as prevailing and anticipated crude oil and natural gas prices and the availability of drilling equipment.

A substantial portion of our economic success depends on factors over which we have no control, including oil and natural gas prices, operating costs, and environmental and other regulatory matters. In our planning process, we focus on maintaining financial flexibility and maintaining a low cost structure in order to reduce our vulnerability to these uncontrollable factors.

See "Item 1A: Risk Factors" for additional risks and factors which could have a material adverse effect on our business, financial condition and results of operations.

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Stock Based Equity Compensation Plan Information

At December 31, 2012, we had approximately 1.4 million vested outstanding stock options issued under our stock based equity compensation plans. Of the total 1.4 million outstanding vested options, 1.2 million had exercise prices below the closing market price of our common stock on December 31, 2012 of $2.81.

For additional detail about our stock based equity compensation plans, see "Executive Compensation-Employee Benefit Plans" under Item 11 and as incorporated by reference from our Proxy Statement on Schedule 14A.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which 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 assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Below, we provide expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Notes to the Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.

Oil and Gas Producing Activities

We account for our oil and gas activities using the full cost method. As prescribed by full cost accounting rules, all costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of oil and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration and development activities are also capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs are depleted on the equivalent unit-of-production method, based on proved oil and gas reserves as determined by independent petroleum engineers.

In accordance with full cost accounting rules, Warren is subject to a limitation on capitalized costs. The capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the cost of unproved properties excluded from amortization, as adjusted for related tax effects. If capitalized costs exceed this limit (the "ceiling limitation"), the excess must be charged to expense. There was no impairment charge in 2012, 2011 and 2010.

The costs of certain unevaluated oil and gas properties and exploratory wells being drilled are not included in the costs subject to amortization. Warren assesses costs not being amortized for possible

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impairments or reductions in value and if impairments or a reduction in value has occurred, the portion of the carrying cost in excess of the current value is transferred to costs subject to amortization.

Our estimate of proved reserves is based on the quantities of oil and gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us. The accuracy of our reserve estimates depends in part on the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Revenue Recognition

Oil and gas sales result from undivided interests held by us in various oil and gas properties. Sales of natural gas and oil produced are recognized when delivered to or picked up by the purchaser. Warren accrues for revenue based on estimated pricing and production.

Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board ("FASB") issued ASU 2011-05, "Comprehensive Income: Presentation of Comprehensive Income," ("ASU 2011-05") which amended ASC 220, "Presentation of Comprehensive Income." In accordance with the new guidance, an entity will no longer be permitted to present comprehensive income in its consolidated statements of stockholders' equity. Instead, entities will be required to present components of comprehensive income in either one continuous financial statement with two sections, net income and comprehensive income, or in two separate but consecutive statements. The guidance, which must be applied retroactively, was effective for the Company beginning January 1, 2012. The adoption of ASU 2011-05 did not have a material effect on the Company's consolidated financial statements.

In May 2011, the FASB issued ASU No. 2011-04, "Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs," to develop common requirements for valuation and disclosure of fair value measurements in accordance with U.S. GAAP and International Financial Reporting Standards. This ASU became effective for fiscal years and interim periods within those years beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material effect on the Company's consolidated financial statements.

In December 2011, the FASB issued ASU No. 2011-11, "Disclosures about Offsetting Assets and Liabilities," to improve reporting and transparency of offsetting (netting) assets and liabilities and the related affects on the financial statements. This ASU is effective for fiscal years and interim periods within those years beginning on or after January 1, 2013. We do not expect the adoption of this ASU will have a material effect on the Company's consolidated financial statements.

In February 2013, the FASB issued ASU No. 2013-02, "Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income," ("ASU 2013-02"). ASU 2013-02 finalizes the requirements of ASU 2011-05 that ASU 2011-12 deferred, clarifying how to report the effect of significant reclassifications out of accumulated other comprehensive income. ASU 2013-02 is to be applied prospectively. We do not anticipate that the adoption of this ASU will have a material effect on the Company's consolidated financial statements.

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Results of Operations

Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

Oil and gas sales. Revenue from oil and gas sales increased $18.4 million during 2012 to $121.8 million, a 18% increase compared to 2011. This increase primarily resulted from an increase in oil production and an increase in realized oil prices. Net oil production for 2012 and 2011 was 1.1 MMbbls and 0.9 MMbbls, respectively. Net gas production for 2012 and 2011 was 5.5 Bcf and 5.0 Bcf, respectively. Additionally, the average realized price per barrel of oil for 2012 and 2011 was $96.02 and $91.53, respectively. The average realized price per Mcf of gas for 2012 and 2011 was $2.78 and $3.98, respectively.

Lease operating expense. Lease operating expense increased 8% to $33.1 million ($16.31 per boe) for 2012 compared to $30.6 million ($17.53 per boe) in 2011. Primarily, lease operating expense increased due to a 16% increase in production. Oil lease operating expense increased slightly on a per barrel basis from $19.19 in 2011 to $19.46 per barrel in 2012. This resulted from higher ad valorem taxes and fuel and power costs associated with moving more liquids throughout the central facility during 2012. Additionally, this increase was offset by lower gas severance taxes due to lower natural gas prices.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased $16.7 million for 2012 to $47.2 million, a 55% increase compared to last year. The increase in depletion expense resulted from an increase in the 2012 depletion rate and an increase in production. The 2012 depletion rate increased to $23.26 per boe compared to $17.46 per boe in 2011. The increase in the 2012 depletion rate compared to the 2011 depletion rate on a boe basis reflects a reduction in proved undeveloped gas reserves, due to lower gas prices rendering development uneconomic. Additionally, estimated future development costs and abandonment costs increased from $189 million at December 31, 2011 to $223 million at December 31, 2012.

General and administrative expenses. General and administrative expenses increased $5.0 million in 2012 to $19.8 million, a 34% increase compared to last year. This increase resulted from the severance packages payable to the Company's former Chief Executive Officer and two former Officers totaling $3.5 million ($2.4 million in cash and $1.1 million in non-cash related to the accelerated vesting of stock options). Additionally, consulting expense increased $1.0 million during 2012.

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