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Exhibit 99.1

The following are excerpts from the Company's disclosure in connection with its offering of senior notes.

2014 Marcellus Assets Acquisition

        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 expect to complete the Citrus Acquisition in August 2014.

        The Marcellus Assets are located in the northeast portion of the Marcellus Shale, which is the largest natural gas producing field in the United States. The Marcellus Assets net average production for June 2014 was approximately 82.0 MMcfe/d. Estimated net proved reserves, as of June 30, 2014, totaled approximately 204.8 Bcf. The Marcellus Assets had an estimated total PV-10 Value for proved reserves of $189.9 million as of June 30, 2014.

Our Combined Business

        On a combined basis, after giving effect to the Citrus Acquisition, our business will consist principally of our operations in Pennsylvania, California and Wyoming. Our Pennsylvania business will produce dry natural gas using horizontal drilling and hydraulic fracturing techniques. In California, we produce oil using directional and horizontal drilling in combination with waterflood recovery techniques, and in Wyoming, we produce coalbed methane ("CBM") gas utilizing shallow vertical drilling.

        On a combined basis (Warren information as of December 31, 2013 and Citrus information as of June 30, 2014), we have net proved reserves of 407.3 Bcfe and a PV-10 Value of approximately $694 million. The following table summarizes our combined estimated proved reserves as well as certain operating information for each of our core operating areas, giving effect to the Citrus Acquisition.

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Core Operating Areas

        Pennsylvania.    The Pennsylvania properties we have agreed to acquire in the Citrus Acquisition consist of a concentrated, contiguous acreage position located in Wyoming County, Pennsylvania in the northeast portion of the Marcellus Shale. We will acquire approximately 5,289 net acres in the Citrus Acquisition. As of the closing of the Citrus Acquisition, we will hold an approximate 75% working interest and an approximate 60% net revenue interest in these Marcellus Assets.

        The Marcellus Assets net average gas production for the three months ended March 31, 2014 was approximately 81.5 MMcfe/d and for June 2014 was approximately 82.0 MMcfe/d. The properties have 30 gross (22.5 net) producing wells in the Marcellus. We have identified 26 additional drilling locations in the Lower Marcellus. Estimated net proved reserves as of June 30, 2014 were 204.8 Bcfe, of which 55% were proved developed producing ("PDP"). While the majority of current production and reserves are attributable to the Lower Marcellus formation, we intend to continue testing in the Upper Marcellus, where we have identified 48 additional locations. We have budgeted capital expenditures of $18.7 million relating to the Marcellus Assets during the balance of 2014, $17.2 million to drill 4 gross (3.5 net) and complete 3 gross (2.3 net) wells in the Marcellus Assets, and $1.5 million in midstream capital expenditures.

        The assets we are acquiring include a robust and scalable infrastructure system that will enable further our development of the Marcellus Assets, including a gathering and compression system, takeaway capacity to end markets, a significant local customer, and abundant water supply.

Other Recent Developments

New $750 Million Revolving Credit Facility

        In connection with the Citrus Acquisition, we will enter into an amended and restated five-year reserve based revolving credit agreement (the "Credit Facility"), which will provide for a maximum credit amount of $750 million and an initial borrowing base of $225 million. Upon closing the Citrus Acquisition, we will have an estimated $110.4 million of indebtedness outstanding under the Credit Facility. We expect that the Credit Facility together with our cash flows from operations will provide the necessary liquidity to fund our expanded capital budget.

Lance Peterson to Join Our Board of Directors

        Upon completion of the Citrus Acquisition, Lance Peterson will join our Board of Directors. Lance Peterson co-founded Citrus Energy Corporation in 1989. Mr. Peterson has served as CEO/President of Citrus since its formation. Mr. Peterson has a B.S. in Geological Engineering from the University of North Dakota (1982). Prior to co-founding Citrus Energy Corporation, Mr. Peterson worked in Denver, Colorado as a Reservoir Engineer at Hamilton Brothers Oil Company. Mr. Peterson has overseen the activity and resulting growth of Citrus Energy through asset development in the geographic areas of Mid-Continent, South Texas, Barnett Shale and Marcellus Shale. He has more than 31 years of experience in the oil and gas industry.

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Preliminary Q-2 Financial Results

        Our preliminary results for the quarter ended June 30, 2014 are as follows:

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revenues increased 14% to $35.0 million for the second quarter of 2014, compared to $30.7 million in the second quarter of 2013.



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natural gas production increased approximately 3% to 1.63 Bcf in the second quarter of 2014, compared to 1.59 Bcf for the second quarter of 2013.



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oil production increased approximately 8% to 281,434 Bbls for the second quarter of 2014, compared to 261,639 barrels of oil produced in the second quarter of 2013.

        The average realized price per barrel of oil was $97.59 for the second quarter of 2014, compared to $95.60 for the second quarter of 2013. Additionally, the average realized price per Mcf of natural gas was $3.76 for the second quarter of 2014, compared to $3.60 for the second quarter of 2013. These realized commodity prices exclude the cash effect of derivative activities.

        Our capital expenditures during the second quarter of 2014 were approximately $34 million, the majority of which was spent in our California assets.

        The estimated oil and gas revenue of Citrus and TLK for the quarter ending June 30, 2014 was approximately $23.7 million. Citrus and TLK produced approximately 6.9 billion cubic feet of natural gas in the second quarter of 2014, with an average realized price of $3.43 per Mcf.

        These financial results are preliminary pending the completion of their review by our auditors and those of Citrus and TLK.

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Summary Historical and Pro Forma Combined Financial and Other Data

        The following tables show our summary historical consolidated financial data and our summary unaudited pro forma financial data, each for the periods and as of the dates indicated. The summary historical statement of operations data for the years ended December 31, 2011, 2012 and 2013 and the balance sheet data as of December 31, 2012 and 2013 are derived from our audited consolidated financial statements included in this offering memorandum.

        The summary historical statement of operations data for the three months ended March 31, 2013 and 2014 and the balance sheet data as of March 31, 2014 are derived from our unaudited consolidated financial statements included in this offering memorandum. The historical statement of operations data for the twelve months ended March 31, 2014 is derived by summing our statement of operations data for our year ended December 31, 2013 and the three months ended March 31, 2014 and then deducting our statement of operations data for the three months ended March 31, 2013. The summary unaudited consolidated financial data have been prepared on a consistent basis with our audited consolidated financial statements. In the opinion of management, such summary unaudited consolidated financial data reflect all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the periods presented. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received from oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors.

        The summary unaudited pro forma condensed combined financial data assumes that the Citrus Acquisition, this offering, the issuance of approximately 6.7 million shares of our common stock as part of the consideration for the Citrus Acquisition and the closing of our amended and restated credit facility, including borrowing thereunder to fund a portion of the consideration for the Citrus Acquisition, had taken place on March 31, 2014, in the case of the unaudited pro forma combined balance sheet data, and on January 1, 2013, in the case of the pro forma combined statement of operations data for the year ended December 31, 2013, the three months ended March 31, 2014 and the twelve months ended March 31, 2014.

        These data are subject and give effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this offering memorandum. The summary unaudited pro forma consolidated financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the Citrus Acquisition and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

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        Our historical and pro forma results should be read in conjunction with "Capitalization," "Selected Historical Consolidated Financial Data" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere herein and our consolidated historical and pro forma financial statements and related notes included in this offering memorandum.

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Non-GAAP Financial Measures and Reconciliations

        In this offering memorandum, the terms "EBITDA" and "Adjusted EBITDA" are used. EBITDA is a non-GAAP financial measure and is equivalent to earnings before interest, income taxes, depletion, depreciation, amortization and accretion expenses. Adjusted EBITDA is EBITDA, further adjusted to exclude stock-based compensation and unrealized gain or losses on derivatives. We believe EBITDA and Adjusted EBITDA are important financial measurement tools that facilitate comparison of our operating performance and provide information about our ability to service or incur indebtedness and pay for our capital expenditures. This information differs from measures of performance determined in accordance with GAAP and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. These measures are not necessarily indicative of operating profit or cash flow from operating activities as determined under GAAP and may not be equivalent to similarly titled measures of other companies.

        Our management uses Adjusted EBITDA in a number of ways to assess our combined financial and operating performance, and we believe this measure is helpful to management and investors in identifying trends in our performance. Adjusted EBITDA helps management identify controllable expenses and make decisions designed to help us meet our current financial goals and optimize our financial performance while neutralizing the impact of capital structure on results. Accordingly, we believe this metric measures our financial performance based on operational factors that management can impact in the short-term, namely our cost structure and expenses.

        Other companies may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. Adjusted EBITDA also has limitations as an analytical tool and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include that Adjusted EBITDA:

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does not reflect our cash expenditures, or future requirements, for capital expenditures or contractual commitments;



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does not reflect changes in, or cash requirements for, our working capital needs;



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does not reflect our interest expense, or the cash requirements necessary to service interest on or principal payments of our debt;



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does not reflect certain other non-cash income and expenses; and



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excludes income taxes that may represent a reduction in available cash.

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        We reconcile this non-GAAP financial measure to our net income, which is its most directly comparable financial measure calculated and presented in accordance with GAAP. The table below reconciles our historical net income to Adjusted EBITDA.

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Oil and Natural Gas Reserves

        The following tables present Warren's estimated proved oil and natural gas reserves and the PV-10 Value of our interests in net reserves in producing properties as of December 31, 2013, 2012 and 2011 and Citrus' estimated proved oil and natural gas reserves and the PV-10 Value of its interests in producing properties as of June 30, 2014, in each case based upon reserve reports prepared by Netherland, Sewell & Associates, Inc. The PV-10 Values shown in the tables are not intended to represent the current market value of the estimated oil and natural gas reserves we own or are acquiring in the Citrus Acquisition. See "Business—Oil and Natural Gas Reserves."

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        There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate either negatively or positively. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Production Volumes, Sales Prices and Production Costs

        The following table summarizes our net oil and natural gas production volumes, our average sales prices and expenses for the periods indicated. Our production is attributable to our direct interests in producing properties. For these purposes, our net production will be production that is owned by us,

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after deducting royalty, limited partner and other similar interests. The lease operating expenses shown relates to our net production. See "Business—Production Volumes, Sales Prices and Production Costs."

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ADDITIONAL RISK FACTORS

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:

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



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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;



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political and economic uncertainty and socio-political unrest;



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



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



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



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



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the level of global inventories;



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



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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;



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weather conditions and changes in weather patterns;



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



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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;



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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;



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risks associated with operating drilling rigs; and



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



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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:



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reduction of our revenues, operating income and cash flows;



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



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cause certain of our properties to become economically unviable;

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



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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. 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

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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 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

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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

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pursue legal actions to enforce compliance as well as to seek damages for non-compliance with 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:

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effectively controlling the level of pressure flowing from particular wells;



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landing our wellbore in the desired drilling zone;



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



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running our casing the entire length of the wellbore; and



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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:

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the ability to fracture stimulate the planned number of stages;



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



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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.

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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 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:

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



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the risk of title defects discovered after closing;



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inaccurate assumptions about revenues and costs, including synergies;



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significant increases in our indebtedness and working capital requirements;



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



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



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the potential environmental problems and costs;



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the assumption of unknown liabilities;



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limitations on rights to indemnity from the seller;



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the diversion of management's attention from other business concerns;



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increased demands on existing personnel and on our corporate structure;



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disputes arising out of acquisitions;



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customer or key employee losses of the acquired businesses; and



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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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CAPITALIZATION

        The following table sets forth our unaudited capitalization as of March 31, 2014:

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on an actual basis;



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on an as adjusted basis to give effect to the completion of the Citrus Acquisition, to our closing of the amendment and restatement of our Credit Facility, including related borrowings under our Credit Facility to fund a portion of the acquisition consideration, to our issuance of approximately 6.7 million shares of common stock as part of the acquisition consideration and to the issuance of the notes offered hereby and our application of the estimated net proceeds from this offering in the manner described in "Use of Proceeds."

        This table should be read in conjunction with, and is and is qualified in its entirety by reference to, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical financial statements and the accompanying notes included elsewhere in this offering memorandum. See "Summary—Summary Historical and Pro Forma Combined Financial and Other Data" and "Selected Historical Consolidated Financial Data."

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Capital Expenditure Program

        We began 2014 with a capital expenditure budget of $116 million for the year, of which we had spent approximately $40.5 million as of June 30, 2014, consisting of $77.1 million for California oil activities and $38.9 million for Wyoming activities. Upon closing of the Citrus Acquisition, we anticipate increasing our capital budget for fiscal year 2014 from $116 million to $135 million. The following table summarizes our budgeted capital expenditures for 2014.

Senior Credit Facility

        In connection with the Citrus Acquisition, we will enter into a five-year, Third Amended and Restated Credit Agreement with Bank of Montreal, as Administrative Agent (the "Amended Credit Facility"), which will provide 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 will be substantially similar to the terms of our Existing Credit Facility. Upon closing of the Citrus Acquisition, we will have an estimated $110 million of indebtedness outstanding under our Amended Credit Facility. As of March 31, 2014, as adjusted to give effect to the Citrus Acquisition and the related financings, including this offering and borrowings under our Amended Credit Facility to fund a portion of the acquisition consideration, we would have had total liquidity of approximately $116.5 million, comprised of approximately $1.8 million of cash and cash equivalents and $114.6 million of availability under our Amended Credit Facility.

Areas of Exploration and Development Activities

        Upon consummation of the Citrus Acquisition, our exploration and development activities will be focused primarily in our three core operating areas: directional and horizontal drilling in combination with waterflood oil recovery projects in California, CBM and other deep formation development in our Rocky Mountain projects in the Washakie Basin of Wyoming, and production of dry natural gas using

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horizontal drilling and hydraulic fracturing techniques in the Marcellus Shale in Pennsylvania. The table below highlights our main areas of activity including the Marcellus Assets:

Pennsylvania

        The Pennsylvania properties we have agreed to acquire in the Citrus Acquisition consist of a concentrated, contiguous acreage position located in Wyoming County, Pennsylvania in the northeast portion of the Marcellus Shale. We will acquire approximately 5,289 net acres in the Citrus Acquisition. As of the closing of the Citrus Acquisition, we will hold an approximate 75% working interest and an approximate 60% net revenue interest in these Marcellus Assets.

        The Marcellus Assets net average production for the three months ended March 31, 2014 and for the month of June 2014 was approximately 81.5 MMcfe/d and 82.0 MMcfe/d, respectively. The properties have 30 gross (22.5 net) producing wells in the Marcellus. We have identified 26 additional drilling locations in the Lower Marcellus. Estimated net proved reserves as of June 30, 2014 were 204.8 Bcfe, of which 55% were proved developed producing ("PDP"). While the majority of current production and reserves are attributable to the Lower Marcellus formation, we intend to continue testing in the Upper Marcellus, where we have identified 48 additional locations. We have budgeted capital expenditures of $18.7 million relating to the Marcellus Assets for the balance of 2014, $17.2 million to drill 4 gross (3.5 net) and complete 3 gross (2.3 net) wells in the Marcellus Assets, and $1.5 million in midstream capital expenditures. Citrus began development of its Marcellus Shale acreage in 2009, and established first production in 2010. Citrus successfully drilled and completed 18 gross horizontal gas wells between 2010 and 2012 (four wells in 2010, ten wells in 2011, and four wells in 2012). In 2013 through first quarter 2014, Citrus drilled an additional 15 wells and completed 12 of those wells, with an additional 3 wells anticipated to be completed by Warren in the 3rd quarter of 2014.

        The assets we are acquiring include a robust and scalable infrastructure system that will further enable our development of the Marcellus Assets, including: a gathering and compression system, takeaway capacity to end markets, a significant local customer, and abundant water supply.

        Gathering system facilities, built and operated by Regency (formally PVR), service the entirety of the Marcellus Assets. The gathering system has been completed to tie-in all existing wells and an agreement is in place to hook up gathering lines to all future wells as we continue development. The Regency compression system, in the permitting stage for the second station, includes two separate stations with 24,000 of combined horsepower with a maximum capacity of 210 MMcf/d of production. The system is expected to be completed in the third quarter of 2015. Upon completion, the system will be divided into four operating segments, which will allow the allocation of horsepower to segments that will most benefit from compression and increase well performance.

        There is sufficient takeaway capacity for the Marcellus Assets, with 285,000 gross MMBtu/day of capacity on the entire position. We will have a supply contract with a subsidiary of Procter & Gamble, providing that buyer first priority for up to 45,000 MMBtu/day. The customer under that contract has

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elected to terminate the agreement effective June 10, 2015. Excess volumes can be delivered to the north to Tennessee Pipeline's 300 Line (120,000 MMBtu/day), which provides access to the East Coast markets, or to the south, to the Transco interstate pipeline (120,000 MMBtu/day), through UGI's Auburn I and Auburn II pipelines. With bi-directional flow ability, we will have the option to flow gas to the pipeline with the lowest basis differential. The two main sources of water for the Marcellus Assets are an impoundment pond with capacity of 100,000 barrels of fresh water and a permit to extract 23,810 bbls/d from the Susquehanna River through 2017. These sources are sufficient for all water needs with excess water sold to other operators. 100% of the fresh water is transported via fast line reducing the cost of trucking and community impact. We will recycle 100% of flowback water in subsequent completions.

Estimated Proved Reserves

        The following tables present Warren's estimated proved oil and natural gas reserves and the PV-10 Value of our interests in net reserves in producing properties as of December 31, 2013, 2012 and 2011 and Citrus' estimated proved oil and natural gas reserves and the PV-10 Value of its interests in producing properties as of June 30, 2014, in each case based upon reserve reports prepared by NSAI. The PV-10 Values shown in the tables are not intended to represent the current market value of the estimated oil and natural gas and oil reserves we own or will acquire from Citrus.

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Productive Wells

        The following table sets forth our combined gross and net productive wells after giving effect to the Citrus Acquisition as of December 31, 2013:

        Gross wells represent all wells in which we have a working interest. Net wells represent the total of our fractional undivided working interest in those wells. Productive wells include producing wells and wells mechanically capable of production.

Oil and Natural Gas Acreage

        The following table sets forth our combined acreage position after giving effect to the Citrus Acquisition, as of December 31, 2013 for Warren and June 30, 2014 for Citrus:

Oil and Natural Gas Marketing

        Our natural gas production is delivered into natural gas pipelines for transportation located primarily in Pennsylvania and Wyoming and is sold to various purchasers for later re-marketing or end use. The majority of all of our natural gas is sold under monthly contracts that allow for periodic adjustments in pricing according to market demands. The prices and marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be predicted, including seasonal variations, general market supply and other fluctuations. In Pennsylvania, we will have a fully developed, in-place gathering system to support full field development. All of the Marcellus volumes will be gathered by Regency with sufficient takeaway capacity (285,000 gross MMBtu/d capacity on entire position). The first priority is to deliver up to 45,000 MMBtu/d to a local paper products manufacturer with excess capacity being delivered north to Tennessee (120,000 MMBtu/d) or south to Transco (120,000 MMBtu/d). We have bi-directional flow ability giving us the flexibility to access the market with the most favorable pricing on a daily basis. In the Atlantic Rim of the Washakie Basin, Wyoming we sell our natural gas at the Rocky Mountain Colorado Interstate Gas ("CIG") market price. The CIG price typically has a negative basis differential below the NYMEX Henry Hub prompt

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month natural gas price. Fluctuations between spot and index prices can significantly impact the overall differential to the Henry Hub. We believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as we believe there are a significant number of readily available purchasers in the market.

State Regulation

        In the areas of Pennsylvania where we will conduct operations upon closing the Citrus Acquisition, water sourcing and wastewater disposal are regulated both by the Pennsylvania Department of Environmental Protection, or PADEP, as well as the Susquehanna River Basin Commission, or SRBC. The SRBC is a federal interstate watershed agency that oversees the withdrawal and use of surface water and groundwater from the Susquehanna River Basin for natural gas development and regulates interbasin transfers of produced fluids. The SRBC also restricts water withdrawal rates during periods of reduced precipitation to avoid adverse impacts to the water resources within the Susquehanna River Basin. The PADEP implements a statewide program governing all aspects of natural gas development. This program includes a requirement that operators submit a water management plan for DEP approval prior to the issuance of drilling permits. The PADEP imposes extensive operational and design standards on impoundments and pits that store freshwater or produced water associated with natural gas development. Discharges of produced water to streams in Pennsylvania are prohibited unless strict effluent limits are achieved. The EPA, rather than DEP administers the injection well program in Pennsylvania. Very few injection wells have been permitted in Pennsylvania to accept produced water from unconventional wells. In December of 2013, the PADEP proposed additional regulations governing the permitting and operation of natural gas wells. These regulations, if promulgated as proposed, are likely to increase significantly the costs to dispose of produced water, which could have a material adverse effect on our business, financial condition and results of operations.

Employees

        At March 31, 2014, we had 72 full-time employees. Upon completion of the Citrus Acquisition, approximately 20 Citrus employees will become full-time employees of Warren, including individuals who will assume the roles of Vice President of Business Development and Marcellus Operations and Vice President of Marcellus Land. We believe that our relationships with our employees are good. None of our employees are covered by a collective bargaining agreement. From time to time, we use the services of independent consultants to perform various professional services, particularly in the areas of geological, permitting and environmental assessment activities. Independent contractors often perform well drilling and production operations, including pumping, maintenance, dispatching, inspection and testing.

Offices

        Our principal executive offices are located at 1114 Avenue of the Americas, 34^th Floor, New York, NY 10036, and our telephone number is (212) 697-9660. We lease approximately 4,178 square feet of office space for our New York office under a lease that expires in May 2023. Our oil and gas operations office in Casper, Wyoming occupies 1,174 square feet under a lease that expires in October 2014 and our oil and gas operations office in Long Beach, California occupies 14,201 square feet of space under a lease that expires in April 2020. We also have field offices in Roswell, New Mexico and Rawlins, Wyoming. Following the closing of the Citrus Acquisition, we will sublease from Citrus approximately 4,988 square feet of office space in Plano, Texas under a lease that expires in January 2016. We also intend to have offices in Denver, Colorado and a field office and yard lease in Pennsylvania following the Citrus Acquisition. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

Legal Proceedings

        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

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("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.

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