UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

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

Date of Report: May 30, 2013
(Date of earliest event reported)

Warren Resources, Inc.
(Exact name of Registrant as specified in its charter)

1114 Avenue of the Americas, 34^th Floor, New York, New York 10036
(Address of principal executive office)

(212) 697-9660
(Registrant's telephone number including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

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Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01.    Regulation FD Disclosure.

        On May 30, 2013, Warren Resources, Inc. ("Warren") issued a press release announcing the commencement of a private offering to eligible purchasers, subject to market and other conditions, of $200,000,000 in aggregate principal amount of a new series of senior notes due 2021 (the "Notes"). A copy of the press release is furnished as Exhibit 99.1 to this Current Report on Form 8-K and is incorporated herein by reference.

        The offer and sale of the Notes will not be registered under the Securities Act of 1933, as amended (the "Securities Act"), or the securities laws of any state, and the Notes may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements under the Securities Act and applicable state securities laws. The Notes may be resold by the initial purchasers pursuant to Rule 144A and Regulation S under the Securities Act. The information contained in this Current Report on Form 8-K, including Exhibit 99.1, is neither an offer to sell nor a solicitation of an offer to buy any of the Notes in the offering or any other securities of Warren.

        In connection with the commencement of the private offering of the Notes, we are providing updated disclosures with respect to us, our core operating areas, our other financial data, our reconciliation of net income to EBITDA and Adjusted EBITDA, our production volumes, sales prices and production costs and recent developments contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012 and our quarterly report on Form 10-Q for the period ending March 31, 2013.

        The information in this Item 7.01 includes "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act concerning Warren's operations, economic 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, Warren claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although Warren 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 Warren's expectations include, but are not limited to, Warren'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 Warren 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. 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.

(i)    Warren Resources, Inc.

        We are an independent energy company engaged in the exploration, development, production and acquisition of domestic oil and natural gas properties. Our development and production activities are currently focused on two geographic areas: the Los Angeles Basin in California and the Greater Green

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River Basin in Wyoming. In California, we produce oil from the northern section of the Wilmington field, which is the third largest oilfield in the United States. In Wyoming, we produce natural gas from the Atlantic Rim area of the Washakie basin (the "Atlantic Rim Project"). We focus on increasing reserves and production from these properties while reducing costs of operations.

        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. As of December 31, 2012, we had estimated net proved reserves of 24.9 MMBoe, with a standardized measure of discounted future net cash flows ("Standardized Measure") of $459.9 million, and a PV-10 Value of $494.9 million, which consisted primarily of 16.4 MMBbls of oil from our California properties and 51.2 Bcfe of natural gas, primarily from our Wyoming properties. For the three months ended March 31, 2013, our average daily production was approximately 11,210 barrels of oil equivalent per day ("Boe/d") gross (5,700 Boe/d net), which consisted of approximately 3,516 gross (2,850 net) Boe/d of oil from California and approximately 7,694 gross (2,850 net) Boe/d of natural gas, primarily from Wyoming. We recently increased our 2013 capital expenditure budget by $15 million to $73 million.

        The following table summarizes our estimated proved reserves as well as certain operating information for each of our core operating areas as of the date and for the period presented.

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Core Operating Areas

        California.    Our California operations consist of the Wilmington Townlot Unit (the "WTU") and the North Wilmington Unit (the "NWU") in the Wilmington field of the Los Angeles Basin of California. The Wilmington field has produced over 2.5 billion barrels of oil since its discovery in the 1930s. We have budgeted $53 million for drilling and facilities in California for 2013, with 23 wells planned.

        Wilmington Townlot Unit.    The WTU is located in the northern part of the Wilmington field. The WTU is a unitized oil field consisting of 1,440 gross (1,424 net) acres and has produced more than 149 million barrels of oil from primary and secondary production. As of March 31, 2013, we held an approximate 98.9% working interest and an approximate 81.0% net revenue interest in the WTU.

        During March 2013, we averaged 3,147 barrels of oil per day ("Bbls/d") gross (2,550 Bbls/d net) production in the WTU. As of December 31, 2012, there were 118 gross (117 net) producing wells in the WTU. In addition, estimated proved reserves as of December 31, 2012 were 15.3 MMBbls gross (12.4 MMBbls net), of which approximately 55% were proved developed producing ("PDP"), 1% were proved developed non-producing ("PDNP"), and 44% were proved undeveloped ("PUD").

        North Wilmington Unit.    The NWU is located in the Wilmington field adjacent to the east of the WTU. The NWU is a unitized oil field consisting of approximately 1,036 gross and net acres. As of March 31, 2013, we held a 100% working interest and an approximate 84.7% net revenue interest in the NWU.

        During March 2013, we averaged 349 Bbls/d gross (295 Bbls/d net) production in the NWU. As of December 31, 2012, there were 26 gross (26 net) producing wells in the NWU. In addition, estimated proved reserves as of December 31, 2012 were 4.7 MMBbls gross (4.0 MMBbls net), of which approximately 27% were PDP, none were PDNP, and 73% were PUD.

        Wyoming.    The Washakie Basin is located in the southeast portion of the Greater Green River Basin in southwestern Wyoming. We are focusing our CBM drilling in the Atlantic Rim Project. We also have the rights to drill and develop the deeper, conventional formations ("deep rights") in some, but not all, of the acreage in the Atlantic Rim area. We have budgeted $20 million for drilling and facilities expenditures in Wyoming for 2013, with 25 wells planned.

        CBM.    Commercial CBM production in the Washakie Basin was initially established in 2002 on the eastern rim of the Washakie Basin by us and another independent energy company. Current development in the Washakie Basin is targeting shallow Mesa Verde coalbeds.

        The Washakie Basin represents our largest acreage position. As of December 31, 2012, we owned 114,737 gross (89,013 net) acres prospective for CBM development in the Washakie Basin, of which 75,841 net acres were undeveloped. This area contains approximately 150 gross identified drilling locations, primarily on 80-acre well spacing, and over 60 well stimulation opportunities. As of December 31, 2012, the estimated proved developed reserves for the 144 CBM wells drilled and producing in this area in this basin were 92 Bcf gross (49.4 Bcf net) on 80-acre well spacing.

        Our Atlantic Rim Project comprises approximately 113,275 gross (87,746 net) acres on the eastern rim of the Washakie Basin. The Pacific Rim area of the Washakie Basin (the "Pacific Rim Project") comprises approximately 1,462 gross acres (1,267 net acres) on the western rim of the Washakie Basin, in which we are not currently developing.

        Deep Rights.    In addition, we own approximately 90,124 gross (71,791 net) undeveloped acres of deep rights below our CBM formations in the Atlantic Rim area. The deep acreage is potentially prospective for hydrocarbon production from the Niobrara Shale and other deep formations. The

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acreage is primarily located in the southern portion of the eastern Washakie Basin in Wyoming and is adjacent to and north of the Colorado border.

        We are currently considering possibilities for developing the Niobrara Shale and other deep formations, including joint ventures, cooperative development agreements and joint participation agreements. We estimate that the Niobrara Shale formation is at depths between 4,000 and 10,000 feet. Successful Niobrara Shale oil wells that have been developed in southern Wyoming and northern Colorado are typically drilled horizontally, or vertically, with multiple-stage fracturing.

        Our initial pod, the Sun Dog sub-area, commenced production in April 2002. Currently the Sun Dog sub-area consists of 113 wells. During March 2013, production from 110 producing wells averaged approximately 13,290 gross (7,460 net) Mcf/d of gas. Based on a report from Netherland, Sewell & Associates, Inc. as of December 31, 2012, estimated proved developed reserves for the wells in the Sun Dog sub-area 43.4 Bcf gross (24.4 net) Bcf. We currently own a working interest of approximately 67% in the wells drilled in the initial PA ("Participating Area") of the Sun Dog sub-area. Our working interest will be approximately 69% if the existing sub-area is fully drilled and developed.

        The Doty Mountain sub-area consists of 59 CBM wells on 80-acre spacing. During March 2013, these wells were producing approximately 10,530 gross (6,500 net) Mcf/d of natural gas. Based on a report from Netherland, Sewell & Associates, Inc. as of December 31, 2012, estimated proved reserves for the wells in the Doty Mountain sub-area were 30.2 gross (18.4 net) Bcf. We currently own an approximate 73% working interest in the wells drilled in the initial PA of the Doty Mountain sub-area. Our working interest will be approximately 76% if the existing sub-area is fully drilled and developed.

        The original CBM pilot was a 24-well program originally drilled in 2003 to establish the Blue Sky sub-area. During 2005, we drilled 11 additional CBM wells to reduce the well spacing and accelerate de-watering. Based on prior desorption, permeability, pressure build-up and other tests, we believe that as the wells dewater, they should exhibit daily production rates and a CBM production curve similar to other CBM wells in the Atlantic Rim project. However, in early 2009, operations were suspended due to economics and remain shut-in. In 2011 the BLM required a 25 well drilling program in the area, which is now designated the Grace Point sub-area, to establish the larger Spyglass Hill Unit. These 25 wells are currently de-watering and producing and met the BLM productivity requirement in March 2012 to validate the Spyglass Hill Unit. During March 2013, these wells produced approximately 910 gross (630 net) Mcf/d of natural gas. Based on a report from Netherland, Sewell & Associates, Inc. as of December 31, 2012, estimated proved reserves for the wells in the Grace Point sub-area were 8.0 gross (5.6 net) Bcf. We own and approximate 86% working interest in the wells drilled in the Grace Point sub-area.

        The Catalina Unit consists of 71 CBM wells. During March 2013, gross production from the Catalina unit averaged approximately 13,260 gross (1,370 net) Mcf/d of natural gas. We currently own a working interest of approximately 12.5% in the PA in the Catalina Unit. Based on a report from Netherland, Sewell & Associates, Inc. as of December 31, 2012, estimated proved reserves for the wells in the Catalina unit were 10.2 Bcf gross (1.0 net) Bcf. Because we have a larger working interest in the undrilled locations, our working interest in the unit will be approximately 22% if the existing unit is fully drilled and developed.

Asset Summary

        We have 25 to 30 MMBbl resource potential in California and 250 to 300 Bcf resource potential in Wyoming.

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(ii)   Other Financial and Operating Data

Reconciliation of Net Income to EBITDA and Adjusted EBITDA

        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 EBITDA and Adjusted EBITDA in a number of ways to assess our combined financial and operating performance, and we believe these measures are helpful to management and investors in identifying trends in our performance. EBITDA and 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 these metrics measure our financial performance based on operational factors that management believes can impact our results in the short-term, namely our cost structure and expenses.

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

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



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



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



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



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

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

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 and depreciation, depletion and amortization shown relate to our net production.

(iii) Recent Developments

Business Trends and Capital Expenditure Program

        On May 20, 2013, we announced an increase in our capital expenditure budget by $15 million to $73 million. These additional expenditures will be used to drill 25 new CBM wells in the Spyglass Hill Unit, where we hold approximately 67,000 net acres. This drilling will preserve our acreage in the Unit through June 2014. We intend to utilize new well stimulation design in these wells and to leverage our recently-acquired midstream assets in connection with production from these new wells. Additionally, we sell our natural gas at Rocky Mountain CIG prices, which is traditionally lower than NYMEX prices. The current differential between NYMEX and Rocky Mountain CIG has narrowed and was $0.26 for April 2013. We expect these additional wells to be placed into production in the latter part of 2013.

        We intend to fund 2013 capital expenditures primarily with cash flow from operations.

        Additionally, we plan to stimulate 15 previously drilled wells in our Atlantic Rim Project.

        The information in this Current Report, including Exhibit 99.1, is being furnished pursuant to Item 7.01 of Form 8-K and shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section or Sections 11 and 12(a)(2) of the Securities Act.

Item 9.01.    Financial Statements and Exhibits.

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SIGNATURES

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

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EXHIBIT INDEX

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QuickLinks

Item 7.01. Regulation FD Disclosure.

Item 9.01. Financial Statements and Exhibits.