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  • Location: Texas 
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    2012 ANNUAL REPORT PETROLEUM S AGGRESSIVELY DRILLING THE WILLISTON BASIN


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    CoRpoRAte pRofile We are an independent exploration and production Our management team has a proven track record in company focused on the acquisition and development identifying, acquiring and executing large, repeatable of unconventional oil and natural gas resources. As development drilling programs, which we refer to of December 31, 2012, we accumulated 335,383 net as “resource conversion” opportunities, and has leasehold acres in the Williston Basin. We are currently substantial experience in the Williston Basin. We have focused on exploiting what we have identified as built our leasehold acreage position in the Williston significant resource potential from the Bakken and Basin primarily through acquisitions in our three Three Forks formations, which are present across primary project areas: West Williston, East Nesson a substantial portion of our acreage. We believe and Sanish. the location, size and concentration of our acreage in our core project areas create an opportunity for us to achieve cost, recovery and production efficiencies through the large-scale development of our project inventory. 2012 HigHligHts Production (MBoepd) 25 Average Daily Production (MBoepd) 22.5 22.5 Annual Production (MBoe) 8,224 20 Operated Wells Drilled (Gross/Net) 117 / 95.8 20.6 Proved Reserves (MMBoe) 143.3 15 Percent Oil 89% 10.7 10 Percent Proved Developed 49% 10.2 5.2 5 4.9 ($ in Millions) Revenue $687 0 2010 2011 2012 Adjusted EBITDA (1) $512 Oil Production Total Production Capital Expenditures $1,149 Reserves (MMBoe) at 12/31/12 ($ in Millions) 150 143.3 Cash and Short-Term Investments $239 Property, Plant and Equipment, Net $2,007 120 Total Assets $2,529 Long-Term Debt $1,200 90 78.7 Total Stockholders’ Equity $795 60 70.0 39.8 Number of Employees 281 30 35.8 17.0 0 (1) Non GAAP Adjusted EBITDA Reconciliation can be found on 2010 2011 2012 the Oasis website at www.oasispetroleum.com. Proved Developed Proved Reserves


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    opeRAtions Our operations are focused on oil, targeting the Williston Basin in North Dakota and Montana. Competitive advantages include: • Large, concentrated acreage positions with an inventory of 2,020 total drilling locations or 14 years at current drilling activity levels • Growing reserves profile - up 82% in 2012 to 143.3 MMBoe • Growing production profile - 110% annual growth in 2012 to 22,469 Boepd • Available liquidity of $987 million at December 31, 2012 • Visible growth in a de-risked resource play • Management with proven resource conversion experience and execution successes West East Total Williston Nesson Sanish Williston Proved Reserves (MMBoe) 94.6 41.4 7.3 143.3 Proved Developed Reserves (% of total) 47% 47% 83% 49% Net Acreage 208,062 118,943 8,378 335,383 Average Daily Production (MBoepd in Q4 2012) 18.5 6.4 2.7 27.6 Production Growth over Q4 2011 84% 84% 63% 82% Montana North Dakota BURKE Operations DIVIDE SHERIDAN EAST NESSON WILLIAMS Canada Bakken Shale United State s ROOSEVELT SANISH Williston Basin North Dakota MOUNTRAIL RICHLAND WEST WILLISTON Montana MCKENZIE DUNN


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    letteR to sHAReHoldeRs We are pleased to report to you on our second full year of operations since our Initial Public Offering in June 2010. In 2012, we doubled production for the second consecutive year, continued to advance the conversion of our large captured oil resource and set new growth records in all of our key operating metrics. ouR stRAtegY foR VAlue CReAtion — ResouRCe ConVeRsion We believe the best way for us to generate attractive long- KeY ACHieVements term per-share value is to grow the business by identifying and capturing large resources in economic plays and then executing large, repeatable drilling programs. We call this Completed and placed on strategy “resource conversion.” production 117 gross (95.8 net) operated wells targeting Over the past five years we have proven the benefits of our the Bakken and Three Forks resource conversion strategy, which include lower reinvestment formations in the Williston Basin. risk, multi-year visible growth potential and the ability to generate operational efficiencies, to deliver increasing per-share value. Increased average daily production to 22,469 barrels of oil equivalent (Boe) per day, up 110% A business strategy is only as good as a company’s ability to over 2011. execute. For Oasis to be successful, we not only had to acquire the right leasehold, but also recruit and retain the right talent to optimally develop our assets. We have assembled a cohesive Reduced average well costs by team of professionals with the requisite expertise to efficiently $1.7 million in the fourth quarter of convert our asset base into value. The large opportunity 2012, down 16% from the average in the first half of 2012. presented by our captured resource combined with our fast-paced and results-oriented culture helped us attract the kind of talent needed for success. As of year-end 2012, we had Grew proved oil and natural gas grown the organization to 281 talented employees, up from 146 reserves at year-end 2012 to 143.3 at year-end 2011 and eight times more than the 35 in place at million barrels of oil equivalent (MMBoe), an increase of 82% over the time of the IPO. year-end 2011. Our extensive industry and technical experience coupled with a proven track record of resource conversion execution provides Increased our leasehold position us with a firm foundation required for achieving our future by 27,953 net acres to 335,383 growth plans. total net acres in the Williston Basin. Ended 2012 with 280 operated spacing units, providing us a 14-year drilling inventory for long-term visible growth potential. This strong performance was made possible by our hard-working, entrepreneurial and motivated employees who are all shareholders. This is the heart of our success and our ability to grow per-share value.


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    A lARge CAptuRed advantages, including the ability to generate operational ResouRCe And An immense efficiencies and cost savings, both of which work to enhance returns. Cost control remains a priority for maintaining and oppoRtunitY enhancing returns, and our declining well costs prove it. In Since our inception, we have focused December 2012, our average drilling and completion cost for our time and energy on the Williston a new Bakken well was $8.8 million, which was 16% lower than Basin, a highly attractive oil province with our average well cost during the first half of 2012 and 10% lower multi-stacked pay zones and substantial than August 2012. oil in place. Over the past six years, oil production in North Dakota alone has We are driving costs down through lower service costs, efficiency grown from 115,142 barrels per day gains, optimization of completion techniques, improved well in December 2006 to a new record of design and increased infill drilling. An important component of 768,853 barrels per day in December our initiative to drive down well costs is our move to pad drilling. 2012, establishing North Dakota as the We estimate that pad drilling can reduce total development costs nation’s second largest oil-producing by 5% to 10% when compared to drilling single wells. Our largely state, up from the third-largest in 2011. contiguous acreage position enables us to efficiently orchestrate the services, equipment, resources and people needed to In our three major operating areas, execute a continuous and aggressive drilling program. In 2013, including West Williston, East Williston we expect to develop 60% to 70% of our wells on pads. and Sanish, we produced 27,556 Boe per day on average during the fourth quarter In 2011, we established Oasis Well Services (OWS), a wholly- of 2012, an increase of over 81% over owned subsidiary that began providing in-house well fourth quarter 2011 production. completion services during the first half of 2012. The creation of OWS is a strategic investment and improves our ability to Having accumulated a leasehold position of control costs as well as quality and surety of service. In March 335,383 net acres in the Williston Basin, we 2012, OWS completed its first frac job and in the last three estimate that 305,000 net acres (91%) are months of 2012 averaged 100 frac stages per month. In 2012, located in the core of the Bakken oil play. OWS generated cost savings of $17.5 million, which was at the Importantly, 264,595 net acres are held by high end of our expectations. production, giving us the ability to control the pace of development and optimize our 2013 outlooK – fuRtHeR impRoVing CApitAl drilling program for greater efficiencies. And opeRAtionAl effiCienCY Of our 280 drilling spacing units, we With the majority of our acreage held by production, we are have identified a primary inventory of moving to full pad development in 2013, which will help us 987 drilling locations with 69% targeting achieve additional economies of scale, reduced well costs and the Bakken oil play and the remainder enhanced returns. Pad drilling will help reduce and shorten rig targeting the Three Forks. When we moves, improve frac utilization, decrease the per-well footprint, include all of the potential Bakken and lower the environmental impact and enable implementation of Three Forks drilling locations on our core central tank batteries to ultimately reduce well and operating acreage, total drilling inventory rises to costs. In 2012, we invested $1,149 million in capital expenditures, 2,020 wells, giving us a 14-year inventory an increase of 72% over the prior year. During the year, we for potential future growth. We operate participated in 231 gross (105.6 net) wells that were completed 91% of our net drilling inventory, which and placed on production, which included 117 gross (95.8 net) enhances our ability to realize continued operated wells. improvements in operational efficiency and control capital spending. Our 2013 capital plan calls for investing a total of $1,020 million, an 11% decrease, but given our operational efficiencies and ouR AdVAntAge cost improvements, we can stretch our dollars to do more with less investment. Although we plan to spend less in 2013 than Our large and concentrated acreage we did in the prior year, we plan to complete 128 gross (92.5 blocks provide us with several competitive net) new operated wells during the year, or just three less net


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    wells than 2012. In addition to the pads, A WoRd of tHAnKs we expect to improve our cost structure through operational efficiencies, vendor The future of Oasis Petroleum has never looked brighter, relationships and well design optimization. but we did not achieve our success easily and we never take it for granted. I want to thank all of our employees, partners, The infrastructure we have in place contractors and our investors for their dedication and support should continue to improve efficiencies of Oasis Petroleum. I would like to sincerely thank our Board of in both revenue realizations and our Directors for their guidance as we continue to build and grow operating cost structure. Our oil and gas this company. infrastructure is substantially complete and will improve realizations for both oil Executive officers now hold 5% of Oasis’ stock, which means our and gas prices. In addition, our saltwater interests are closely aligned with yours, which is the way it should disposal system will dispose of more be. Our goal is to continue building long-term value per share barrels via pipeline, which reduces our through resource conversion, continued execution of our business water handling costs. plan and the application of our team’s talents and expertise across our large and mostly undeveloped acreage positions. Aligning CApitAl stRuCtuRe WitH stRAtegY We are grateful for our shareholders’ support and are working diligently to build value for you. I am proud of our extraordinary At the end of 2012, we had cash and cash accomplishments in 2012. I look forward to continuing on this equivalents of $239 million and when journey with you all. combined with our $750 million undrawn borrowing base (excluding $2 million Sincerely, in letters of credit), our total liquidity position was $987 million. We had $500 million of elected commitments under our $750 million borrowing base. Thomas B. Nusz Chairman of the Board, President and Chief Executive Officer Combined with expected cash flow March 7, 2013 from operations, we have the ability to fully fund our 2013 program without having to access the financial markets. This financial strength provides us with a strong foundation for continued execution of our resource conversion strategy along with the flexibility to take advantage of compelling opportunities.


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    UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K È ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2012 OR ‘ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number: 1-34776 Oasis Petroleum Inc. (Exact name of registrant as specified in its charter) Delaware 80-0554627 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1001 Fannin Street, Suite 1500 Houston, Texas 77002 (Address of principal executive offices) (Zip Code) (281) 404-9500 (Registrant’s telephone number, including area code) Securities Registered Pursuant to Section 12(b) of the Act: Common Stock, par value $0.01 per share New York Stock Exchange (Title of Class) (Name of Exchange) Securities Registered Pursuant to Section 12(g) of the Act: None Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes È No ‘ Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ‘ No È Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes È No ‘ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes È No ‘ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ‘ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer È Accelerated filer ‘ Non-accelerated filer ‘ (do not check if a smaller reporting company) Smaller reporting company ‘ Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ‘ No È Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $2,251,698,496 Number of shares of registrant’s common stock outstanding as of February 22, 2013: 93,602,754 Documents Incorporated By Reference: Portions of the registrant’s definitive proxy statement for its 2013 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2012, are incorporated by reference into Part III of this report for the year ended December 31, 2012.


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    OASIS PETROLEUM INC. FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2012 TABLE OF CONTENTS Part I— Item 1. Business 5 Item 1A. Risk Factors 31 Item 1B. Unresolved Staff Comments 48 Item 2. Properties 49 Item 3. Legal Proceedings 49 Item 4. Mine Safety Disclosures 49 Part II— Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 50 Item 6. Selected Financial Data 52 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 54 Item 7A. Quantitative and Qualitative Disclosure about Market Risk 74 Item 8. Financial Statements and Supplementary Data 77 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 123 Item 9A. Controls and Procedures 123 Item 9B. Other Information 124 Part III— Item 10. Directors, Executive Officers and Corporate Governance 125 Item 11. Executive Compensation 125 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 125 Item 13. Certain Relationships and Related Transactions, and Director Independence 125 Item 14. Principal Accountant Fees and Services 125 Part IV— Item 15. Exhibits, Financial Statement Schedules 126 2


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    CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report on Form 10-K, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements may include statements about: • our business strategy; • estimated future net reserves and present value thereof; • technology; • cash flows and liquidity; • our financial strategy, budget, projections, execution of business plan and operating results; • oil and natural gas realized prices; • timing and amount of future production of oil and natural gas; • availability of drilling, completion and production equipment and materials; • availability of qualified personnel; • owning and operating a services company; • the amount, nature and timing of capital expenditures; • availability and terms of capital; • property acquisitions; • costs of exploiting and developing our properties and conducting other operations; • drilling and completion of wells; • infrastructure for salt water disposal; • gathering, transportation and marketing of oil and natural gas, both in the Williston Basin and other regions in the United States; • general economic conditions; • operating environment, including inclement weather conditions; • competition in the oil and natural gas industry; • effectiveness of risk management activities; • environmental liabilities; • counterparty credit risk; • governmental regulation and the taxation of the oil and natural gas industry; • developments in oil-producing and natural gas-producing countries; • uncertainty regarding future operating results; and • plans, objectives, expectations and intentions contained in this report that are not historical. 3


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    All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We disclaim any obligation to update or revise these statements unless required by Securities law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report on Form 10-K are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. 4


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    PART I Item 1. Business Overview Oasis Petroleum Inc. (together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources in the Montana and North Dakota regions of the Williston Basin. As of December 31, 2012, we have accumulated 335,383 net leasehold acres in the Williston Basin. We are currently exploiting significant resource potential from the Bakken and Three Forks formations, which are present across a substantial portion of our acreage. We believe the location, size and concentration of our acreage in our core project areas create an opportunity for us to achieve cost, recovery and production efficiencies through the large- scale development of our project inventory. Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs, which we refer to as “resource conversion” opportunities, and has substantial Williston Basin experience. In 2012, we completed and placed on production 117 gross operated wells in the Williston Basin. We have built our Williston Basin leasehold acreage position primarily through acquisitions and development in our three primary project areas: West Williston, East Nesson and Sanish. DeGolyer and MacNaughton, our independent reserve engineers, estimated our net proved reserves to be 143.3 MMBoe as of December 31, 2012, of which 49% were classified as proved developed and of which 89% were oil. The following table presents summary data for each of our primary project areas as of December 31, 2012: Estimated net proved 2012 Average Productive reserves as of daily Bakken and Three Forks Wells December 31, 2012 production Project area Net acreage Gross Net MMBoe % Developed Boe/d West Williston 208,062 204 128.8 94.6 47 15,263 East Nesson 118,943 145 67.5 41.4 47 4,936 Sanish 8,378 257 19.9 7.3 83 2,270 Total 335,383 606 216.2 143.3 49 22,469 Our history Oasis Petroleum Inc. was incorporated in February 2010 pursuant to the laws of the State of Delaware to become a holding company for Oasis Petroleum LLC (“OP LLC”), our predecessor, which was formed as a Delaware limited liability company in February 2007 by certain members of our senior management team and certain private equity funds. We completed our initial public offering (“IPO”) in June 2010. In connection with our IPO and related corporate reorganization, we acquired all of the outstanding membership interests in OP LLC in exchange for shares of our common stock. Oasis Petroleum North America LLC (“OPNA”) conducts our exploration and production activities and owns our proved and unproved oil and natural gas properties. In 2011, we formed Oasis Well Services LLC (“OWS”), which provides well services to OPNA, and Oasis Petroleum Marketing LLC (“OPM”), which provides marketing services to OPNA. Our business strategy Our goal is to enhance value by investing capital to build reserves, production and cash flows at attractive rates of return through the following strategies: • Develop our Williston Basin leasehold position. We intend to continue to drill and develop our acreage position to maximize the value of our resource potential. During 2012, we completed and brought on production 117 gross (95.8 net) operated Bakken and Three Forks wells in the Williston Basin. As of 5


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    December 31, 2012, we had 21 gross operated wells waiting on completion and 11 gross operated wells drilling in the Bakken and Three Forks formations. Our 2013 drilling plan contemplates completing approximately 128 gross (92.5 net) operated wells in our project areas. We believe we have the ability to increase or decrease the number of wells drilled during 2013 based on market conditions and program results. • Focus on operational and cost efficiencies. Our management team is focused on continuous improvement of our operations and has significant experience in successfully converting early-stage resource conversion opportunities into cost-efficient development projects. We believe the magnitude and concentration of our acreage within our project areas provide us with the opportunity to capture economies of scale, including the ability to drill multiple wells from a single drilling pad, utilizing centralized production and oil, gas and water fluid handling facilities and infrastructure and reducing the time and cost of rig mobilization. In addition, OWS is expected to continue to provide capital savings and decrease our operated well capital costs going forward. • Adopt and employ leading drilling and completion techniques. Our team is focused on enhancing our drilling and completion techniques to maximize overall well economics. We believe these techniques have significantly evolved over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the implementation of techniques such as drilling longer laterals and more tightly spacing fracturing stimulation stages. We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our operating practices. This continued evolution may enhance our initial production rates, ultimate recovery factors and rate of return on invested capital. • Pursue strategic acquisitions with significant resource potential. As opportunities arise, we intend to identify and acquire additional acreage and producing assets in the Williston Basin to supplement our existing operations. Going forward, we may selectively target additional basins that would allow us to employ our resource conversion strategy on large undeveloped acreage positions similar to what we have accumulated in the Williston Basin. • Maintain financial flexibility and conservative financial position. We are committed to maintaining a conservative financial strategy by managing our liquidity position and leverage levels. As of December 31, 2012, we had no borrowings and $2.2 million of outstanding letters of credit under our revolving credit facility and $737.1 million of liquidity available, including $239.3 million in cash and short-term investments and $497.8 million available under our revolving credit facility. This liquidity position, along with internally generated cash flows, will provide additional financial flexibility as we continue to develop our acreage position in the Williston Basin. We also have access to the public equity and debt markets, and we intend to maintain a conservative, balanced capital structure by prudently raising proceeds from future offerings as additional capital needs arise. Our competitive strengths We have a number of competitive strengths that we believe will help us to successfully execute our business strategies: • Substantial leasehold position in one of North America’s leading unconventional oil-resource plays. As of December 31, 2012, our 335,383 net leasehold acres in the Williston Basin were highly prospective in the Bakken and Three Forks formations and 89% of our 143.3 MMBoe estimated net proved reserves in this area were comprised of oil. We increased our operated drill blocks by 37 through acreage additions and trades during 2012. In addition, we have 264,595 net acres held-by-production as of December 31, 2012. We believe our acreage is one of the largest concentrated leasehold positions that is prospective in the Bakken and Three Forks formations, and much of our acreage is in areas of significant drilling activity by other exploration and production companies. We expect that the scale and concentration of our acreage will enable us to reduce our drilling and completion costs and improve operational efficiency as we transition to full development mode throughout 2013. 6


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    • Large, multi-year project inventory. We believe we have a large inventory of potential drilling locations that we have not yet drilled, a majority of which is operated by us. We plan to complete 128 gross (92.5 net) operated wells in the Williston Basin in 2013. • Management team with proven operating and acquisition skills. Our senior management team has extensive expertise in the oil and gas industry. Our senior technical team has an average of more than 25 years of industry experience, including experience in multiple North American resource plays as well as experience in international basins. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of resource conversion opportunities. In addition, our technical team possesses substantial expertise in horizontal drilling techniques and managing and acquiring large development programs and also has prior experience in the Williston Basin. • Incentivized management team. As of December 31, 2012, our executive officers owned approximately 5% of our outstanding common stock. We believe our executive officers’ ownership interest in us provides them with significant incentives to grow the value of our business for the benefit of all stakeholders. • Operating control over the majority of our portfolio. In order to maintain better control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate. We expect to operate approximately 64% of our gross drilling locations, or 91% of our net drilling locations. As of December 31, 2012, 93% of our estimated net proved reserves were attributable to properties that we expect to operate. Approximately 89% of our 2013 drilling and completion capital expenditure budget is related to operated wells. As of December 31, 2012, our average working interest in our operated and non-operated identified drilling locations was 69% and 12%, respectively. Controlling operations will allow us to dictate the pace of development as well as the costs, type and timing of exploration and development activities. We believe that maintaining operational control over the majority of our acreage will allow us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing hydrocarbon recovery through continuous improvement of drilling and completion techniques. We are also better able to control infrastructure investment to drive down operating costs and increase gas production and oil price realizations. Our operations Estimated net proved reserves The table below summarizes our estimated net proved reserves and related PV-10 at December 31, 2012, 2011 and 2010 for each of our project areas based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers. In preparing its reports, DeGolyer and MacNaughton evaluated properties representing all of our PV-10 at December 31, 2012, 2011 and 2010 in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in oil and natural gas producing activities. Our estimated net proved reserves were determined using the preceding twelve months’ unweighted arithmetic average of the first-day-of-the-month prices and do not include probable or possible reserves. The information in the following table does not give any effect to or reflect our commodity derivatives. For a definition of proved reserves under the SEC rules, please see the “Glossary of oil and natural gas terms” included at the end of this report. For more information regarding our independent reserve engineers, please see “Independent petroleum engineers” below. At December 31, 2012 At December 31, 2011 At December 31, 2010 Proved reserves PV-10(1) Proved reserves PV-10(1) Proved reserves PV-10(1) Project area (MMBoe) (in millions) (MMBoe) (in millions) (MMBoe) (in millions) Williston Basin: West Williston 94.6 $2,066.6 51.6 $1,242.6 22.9 $380.0 East Nesson 41.4 975.6 21.1 479.1 9.6 160.7 Sanish 7.3 202.1 6.0 182.0 7.2 156.4 Total Williston Basin 143.3 3,244.3 78.7 1,903.7 39.7 697.1 Other(2) — — — — 0.1 0.7 Total 143.3 $3,244.3 78.7 $1,903.7 39.8 $697.8 7


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    (1) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable financial measure under accounting principles generally accepted in the United States of America (“GAAP”), because it does not include the effect of income taxes on discounted future net cash flows. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. The oil and gas industry uses PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. See “Reconciliation of PV-10 to Standardized Measure” below. (2) Represents data relating to our properties in the Barnett shale, which we sold in November 2011. Estimated net proved reserves at December 31, 2012 were 143.3 MMBoe, an 82% increase from estimated net proved reserves of 78.7 MMBoe at December 31, 2011 primarily as a result of our 2012 drilling program and well completions. Our proved developed reserves increased 34.2 MMBoe, or 95%, to 70.0 MMBoe for the year ended December 31, 2012 from 35.8 MMBoe for the year ended December 31, 2011, primarily due to our 2012 drilling program, including the completion of 117 gross (95.8 net) operated wells. Our proved undeveloped reserves increased to 73.3 MMBoe for the year ended December 31, 2012 from 42.9 MMBoe for the year ended December 31, 2011 primarily due to our 2012 drilling program. Estimated net proved reserves at December 31, 2011 were 78.7 MMBoe, a 98% increase from estimated net proved reserves of 39.8 MMBoe at December 31, 2010. Our 2011 estimated net proved reserves increased 38.9 MMBoe over our 2010 estimated net proved reserves due to acquisitions, our drilling program and higher oil price assumptions at December 31, 2011. Our commodity price assumption for oil increased $16.83/Bbl to $96.23/Bbl for the year ended December 31, 2011 from $79.40/Bbl for the year ended December 31, 2010. Our proved developed producing reserves increased 18.8 MMBoe, or 111%, to 35.8 MMBoe for the year ended December 31, 2011 from 17.0 MMBoe for the year ended December 31, 2010, primarily due to our drilling program completing 63 gross (49.2 net) operated wells. Our proved undeveloped reserves increased to 42.9 MMBoe for the year ended December 31, 2011 from 22.8 MMBoe for the year ended December 31, 2010 due to our drilling program, significant regional drilling activity, higher commodity price assumptions and higher overall estimated ultimate recoveries using recent drilling and completion techniques. The following table sets forth more information regarding our estimated net proved reserves at December 31, 2012, 2011 and 2010: At December 31, 2012 2011 2010 Reserves Data(1): Estimated proved reserves: Oil (MMBbls) 128.1 69.1 36.6 Natural gas (Bcf) 91.5 57.9 19.4 Total estimated proved reserves (MMBoe) 143.3 78.7 39.8 Percent oil 89% 88% 92% Reserves Data(1): Estimated proved developed reserves: Oil (MMBbls) 62.6 31.8 15.7 Natural gas (Bcf) 44.7 24.5 8.2 Total estimated proved developed reserves (MMBoe) 70.0 35.8 17.0 Percent proved developed 49% 46% 43% Estimated proved undeveloped reserves: Oil (MMBbls) 65.5 37.3 20.9 Natural gas (Bcf) 46.8 33.4 11.2 Total estimated proved undeveloped reserves (MMBoe) 73.3 42.9 22.8 PV-10 (in millions)(2) $3,244.3 $1,903.7 $697.8 Standardized Measure (in millions)(3) $2,259.9 $1,319.5 $485.7 8


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    (1) Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the- month prices for the prior twelve months were $94.68/Bbl for oil and $2.75/MMBtu for natural gas, $96.23/Bbl for oil and $4.12/MMBtu for natural gas, and $79.40/Bbl for oil and $4.38/MMBtu for natural gas for the years ended December 31, 2012, 2011 and 2010, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. (2) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. The oil and gas industry uses PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. See “Reconciliation of PV-10 to Standardized Measure” below. (3) Standardized Measure represents the present value of estimated future net cash flows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses (if applicable), discounted at 10% per annum to reflect timing of future cash flows. Reconciliation of PV-10 to Standardized Measure PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves. The following table provides a reconciliation of PV-10 to the Standardized Measure of discounted future net cash flows at December 31, 2012, 2011 and 2010: December 31, 2012 2011 2010 (In millions) PV-10 $3,244.3 $1,903.7 $697.8 Present value of future income taxes discounted at 10% 984.4 584.2 212.1 Standardized Measure of discounted future net cash flows $2,259.9 $1,319.5 $485.7 The PV-10 of our estimated net proved reserves at December 31, 2012 was $3,244.3 million, a 70% increase from PV-10 of $1,903.7 million at December 31, 2011. This increase was mainly due to an increase in reserves and a reduction in costs, partially offset by lower commodity price assumptions year over year. 9


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    Estimated future net revenues The following table sets forth the estimated future net revenues, excluding derivative contracts, from proved reserves, the present value of those net revenues (PV-10) and the expected benchmark prices used in projecting net revenues at December 31, 2012, 2011 and 2010: At December 31, (In millions) 2012 2011 2010 Future net revenues $7,077.4 $4,034.9 $1,561.3 Present value of future net revenues: Before income tax (PV-10) 3,244.3 1,903.7 697.8 After income tax (Standardized Measure) 2,259.9 1,319.5 485.7 Benchmark oil price ($/Bbl)(1) $ 94.68 $ 96.23 $ 79.40 (1) Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the- month prices for the prior twelve months were $94.68/Bbl for oil and $2.75/MMBtu for natural gas, $96.23/Bbl for oil and $4.12/MMBtu for natural gas, and $79.40/Bbl for oil and $4.38/MMBtu for natural gas for the years ended December 31, 2012, 2011 and 2010, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations at December 31, 2012, 2011 and 2010 are based on costs in effect at December 31 of each year and the twelve-month unweighted arithmetic average of the first-day-of-the-month price for January through December of such year, without giving effect to derivative transactions, and are held constant throughout the life of the properties. There can be no assurance that the proved reserves will be produced within the periods indicated or that prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties. Proved undeveloped reserves At December 31, 2012, we had approximately 73.3 MMBoe of proved undeveloped reserves as compared to 42.9 MMBoe at December 31, 2011. The following table summarizes the changes in our proved undeveloped reserves during 2012 (in MBoe): At December 31, 2011 42,876 Extensions, discoveries and other additions 57,322 Purchases of minerals in place 812 Sales of minerals in place — Revisions of previous estimates (1,223) Conversion to proved developed reserves (26,493) At December 31, 2012 73,294 During 2012, we spent a total of $642.7 million related to the development of proved undeveloped reserves, $90.0 million of which was spent on proved undeveloped reserves that still remain proved undeveloped at year- end. The remaining $552.7 million resulted in the conversion of 26,493MBoe of proved undeveloped reserves, or 62% of our proved undeveloped reserves balance at the beginning of 2012, to proved developed reserves. We added 57,322 MBoe of proved undeveloped reserves across all three of our project areas as a result of our 2012 operated and non-operated drilling program. 10


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    In 2012, we also had a net negative revision of 1,223 MBoe, or 2.9 % of our December 31, 2011 proved undeveloped reserves balance. The primary causes for these revisions were negative well performances partially offset by working interest increases in the proved undeveloped locations. Within portions of the West Williston and East Nesson project areas, actual well results underperformed relative to the proved undeveloped forecasts prepared in 2011. The proved undeveloped forecasts in these areas have been adjusted to reflect these well performances in the 2012 reserve report. The working interest increases arose from acreage trades, non- participation by other interest owners and additional mineral leasing in the reserve locations. Operating costs and realized prices had an immaterial impact on the proved undeveloped reserves balance. All of our proved undeveloped reserves as of December 31, 2012 are expected to be developed within five years of their initial booking. Independent petroleum engineers Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure at December 31, 2012, 2011 and 2010 are based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007) and definitions and current guidelines established by the SEC. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Calgary and Moscow. The firm’s more than 100 professionals include engineers, geologists, geophysicists, petrophysicists and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton has provided such services for over 70 years. The Senior Vice President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve estimates is a Registered Petroleum Engineer in the State of Texas with more than 35 years of experience in oil and gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1974 and he is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any oil, gas or mineral properties, or securities or notes of clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm. Technology used to establish proved reserves In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In order to establish reasonable certainty with respect to our estimated net proved reserves, DeGolyer and MacNaughton employed technologies including, but not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available down hole and production data, seismic data and well test data. Reserves 11


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    attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. In addition to assessing reservoir continuity, geologic data from well logs, core analyses and seismic data related to the Bakken formation were used to estimate original oil in place. In areas where estimated proved reserves were attributed to more than one well per spacing unit, the estimated original oil in place was used to calculate reasonable estimated recovery factors based on experience with similar reservoirs where similar drilling and completion techniques have been employed. Internal controls over reserves estimation process We employ DeGolyer and MacNaughton as the independent reserves evaluator for 100% of our reserves base. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with the independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished for the reserves estimation process. Brett Newton, Senior Vice President of Asset Management, is the technical person primarily responsible for overseeing our reserves evaluation process. He has over 20 years of industry experience with positions of increasing responsibility in engineering and management. He holds both a Bachelor of Science degree and Master of Science degree in petroleum engineering. Mr. Newton reports directly to our Chief Operating Officer. Throughout each fiscal year, our technical team meets with the independent reserve engineers to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following: • Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database; • Review of working interest and net revenue interest in our reserves database against our well system; • Review of realized prices and differentials from index prices from the well profitability report as compared to the differentials used in our reserves database; • Review of updated capital costs prepared by our operations team; • Review of internal reserve estimates by well and by area by our internal reservoir engineers; • Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President of Asset Management; • Review of a preliminary copy of the reserve report by our Chief Operating Officer with representatives from our independent reserve engineers and internal technical staff; and • Review of our reserves estimation process by our Audit Committee on an annual basis. Production, revenues and price history Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically over the last ten years. However, the economic slowdown during the second half of 2008 and through 2009 reduced this demand. In 2010, 2011 and 2012, demand for oil and natural gas increased as the economy recovered. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to 12


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    continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets. The following table sets forth information regarding our oil and natural gas production, realized prices and production costs for the periods indicated. For additional information on price calculations, please see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Year Ended December 31, 2012 2011 2010 Net production volumes: Oil (MBbls) 7,533 3,732 1,792 Natural gas (MMcf) 4,146 1,092 651 Oil equivalents (MBoe) 8,224 3,914 1,900 Average daily production (Boe/d) 22,469 10,724 5,206 Average sales prices: Oil, without realized derivatives (per Bbl) $ 85.22 $ 86.18 $69.60 Oil, with realized derivatives (per Bbl)(1) 86.09 85.15 69.53 Natural gas (per Mcf)(2) 6.52 8.02 6.52 Costs and expenses (per Boe of production): Lease operating expenses(3) $ 6.68 $ 8.36 $ 7.43 Marketing, transportation and gathering expenses 1.13 0.34 0.24 Production taxes 7.66 8.65 7.25 Depreciation, depletion and amortization 25.14 19.16 19.91 General and administrative expenses 6.95 7.52 10.39 Stock-based compensation expenses(4) — — 4.60 (1) Realized prices include realized gains or losses on cash settlements for our commodity derivatives, which do not qualify for and were not designated as hedging instruments for accounting purposes. (2) Natural gas prices include the value for natural gas and natural gas liquids. (3) For the years ended December 31, 2011 and 2010, lease operating expenses exclude marketing, transportation and gathering expenses to conform such amounts to current year classifications. (4) During 2010, we recorded $8.7 million in stock-based compensation expense associated with Class C common unit interests (“C Units”) and discretionary stock awards granted. Stock-based compensation expense related to the amortization of restricted stock and performance share units is included in general and administrative expenses on the Consolidated Statement of Operations. See Note 9 to our audited consolidated financial statements. Net production volumes for the year ended December 31, 2012 were 8,224 MBoe, a 110% increase from net production of 3,914 MBoe for the year ended December 31, 2011. Our net production volumes increased 4,310 MBoe over 2011 due to a successful operated and non-operated drilling and completion program. Average oil sales prices, without realized derivatives, decreased by $0.96/Bbl, or 1%, to an average of $85.22/Bbl for the year ended December 31, 2012 as compared to the year ended December 31, 2011. Giving effect to our derivative transactions in both periods, our oil sales prices increased $0.94/Bbl to $86.09/Bbl for the year ended December 31, 2012 from $85.15/Bbl for the year ended December 31, 2011. Net production volumes for the year ended December 31, 2011 were 3,914 MBoe, a 106% increase from net production of 1,900 MBoe for the year ended December 31, 2010. Our net production volumes increased 2,014 MBoe over 2010 due to a successful operated and non-operated drilling and completion program. Average oil sales prices, without realized derivatives, increased by $16.58/Bbl, or 24%, to an average of $86.18/Bbl for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Giving effect to our derivative transactions in both periods, our oil sales prices increased $15.62/Bbl to $85.15/Bbl for the year ended December 31, 2011 from $69.53/Bbl for the year ended December 31, 2010. 13


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    The following table sets forth information regarding our average daily production for the years ended December 31, 2012 and 2011: Average daily production for the years ended December 31, 2012 2011 2010 Bbls Mcf Boe Bbls Mcf Boe Bbls Mcf Boe Williston Basin: West Williston 13,904 8,152 15,263 6,426 1,278 6,639 1,976 564 2,070 East Nesson 4,586 2,106 4,936 2,333 430 2,404 1,607 215 1,643 Sanish 2,091 1,070 2,270 1,467 750 1,592 1,325 561 1,419 Total Williston Basin 20,581 11,328 22,469 10,226 2,458 10,635 4,908 1,340 5,132 Other(1) — — — — 533 89 — 444 74 Total 20,581 11,328 22,469 10,226 2,991 10,724 4,908 1,784 5,206 (1) Represents data relating to our properties in the Barnett shale, which we sold in November 2011. Productive wells The following table presents the total gross and net productive wells by project area as of December 31, 2012: Bakken and Total wells Three Forks Project area Gross Net Gross Net West Williston 311 176.2 204 128.8 East Nesson 145 67.5 145 67.5 Sanish 257 19.9 257 19.9 Total 713 263.6 606 216.2 All of our productive wells are oil wells. Gross wells are the number of wells, operated and non-operated, in which we own a working interest and net wells are the total of our working interests owned in gross wells. Acreage The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2012 for each of our project areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. Developed acres Undeveloped acres Total acres Project area Gross Net Gross Net Gross Net West Williston 211,701 154,711 73,003 53,351 284,704 208,062 East Nesson 104,969 72,605 66,993 46,338 171,962 118,943 Sanish 41,373 8,373 160 5 41,533 8,378 Total 358,043 235,689 140,156 99,694 498,199 335,383 We have increased our acreage that is held-by-production to approximately 265 thousand net acres at December 31, 2012 from 184 thousand net acres at December 31, 2011. 14


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    Undeveloped acreage The following table sets forth the number of gross and net undeveloped acres as of December 31, 2012 that will expire over the next three years by project area unless production is established within the spacing units covering the acreage prior to the expiration dates: Expiring 2013 Expiring 2014 Expiring 2015 Gross Net Gross Net Gross Net West Williston 7,350 4,948 13,405 9,024 23,431 15,774 East Nesson 26,015 17,513 1,405 946 28,572 19,234 Sanish — — — — 160 3 Total 33,365 22,461 14,810 9,970 52,163 35,011 Drilling activity The following table summarizes our drilling activity for the years ended December 31, 2012, 2011 and 2010. Gross wells reflect the sum of all productive and dry wells, operated and non-operated, in which we own an interest. Net wells reflect the sum of our working interests in gross wells. The gross and net wells represent wells completed during the periods presented, regardless of when drilling was initiated. Year ended December 31, 2012 2011 2010 Gross Net Gross Net Gross Net Development wells: Oil 193 89.9 128 48.4 100 22.7 Gas — — — — 2 0.1 Dry(1) 2 1.9 — — — — Total development wells 195 91.8 128 48.4 102 22.8 Exploratory wells: Oil 38 15.7 9 6.2 14 5.7 Gas — — — — — — Dry — — — — — — Total exploratory wells 38 15.7 9 6.2 14 5.7 Total wells 233 107.5 137 54.6 116 28.5 (1) In 2012, we had two gross development dry hole wells as a result of mechanical failures. Replacement wells were drilled in the same drilling spacing units, which were successful in finding and producing hydrocarbons. Our drilling activity has increased each year since our inception. Exploration wells in 2011 and 2010 primarily focused on delineation and appraisal of the Bakken formation in our West Williston and East Nesson areas. In 2012, we continued this focus on delineation, resulting in substantially all of our acreage being delineated in the Bakken formation and continued delineation in the Three Forks formation as of December 31, 2012. We also continued to participate in a number of wells on a non-operated basis. In 2012, we had two gross development dry hole wells as a result of mechanical failures. Replacement wells were drilled in the same drilling spacing units, which were successful in finding and producing hydrocarbons. In 2012 and 2011, we allocated a portion of the costs for a well that was unsuccessful due to mechanical complications in the Three Forks formation to exploratory dry hole expense. The well was successfully plugged back and completed in the Bakken formation. We did not drill any dry hole wells in 2010. Consistent with our 2013 capital plan, we expect to continue to focus on drilling in the Bakken and Three Forks formations. 15


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    Capital expenditure budget In 2012, we spent $1,148.6 million on capital expenditures, which represented a 72% increase over the $666.0 million spent during 2011. This increase was a result of continued improvement of industry conditions and drilling and completion technology in the Bakken and Three Forks formations as well as increased economics in the area and an increase in total net wells drilled in 2012. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and capital resources—Cash flows used in investing activities.” Our total 2013 capital expenditure budget is $1,020 million, which includes $996 million for exploration and production (“E&P”) capital expenditures and $24 million for non-E&P capital expenditures. Our planned capital expenditures primarily consist of: • $897 million of drilling and completion capital expenditures for operated and non-operated wells (including expected savings from services provided by OWS); • $43 million for constructing infrastructure to support production in our core project areas, primarily related to salt water disposal systems; • $25 million for maintaining and expanding our leasehold position; • $10 million for micro-seismic work, purchasing seismic data and other test work; • $21 million for facilities and other miscellaneous E&P capital expenditures; • $14 million for OWS; and • $10 million for other non-E&P capital, including items such as administrative capital and capitalized interest. While we have budgeted $1,020 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and capital resources.” Our core project areas Williston Basin Our operations are focused in the North Dakota and Montana areas of the Williston Basin. While we have interests in a substantial number of wells in the Williston Basin that target several different zones, our exploration and development activities are currently concentrated in the Bakken and Three Forks formations. Our management team originally targeted the Williston Basin because of its oil prone nature, multiple, stacked producing horizons, substantial resource potential and management’s previous professional history in the basin. The Williston Basin also has established infrastructure and access to materials and services. Regulatory delays are minimal in the Williston Basin due to fee ownership of properties, efficient state and local regulatory bodies and reasonable permitting requirements. The entire Williston Basin is spread across North Dakota, South Dakota, Montana and parts of southern Canada. The basin produces oil and natural gas from numerous producing horizons including, but not limited to, the Bakken, Three Forks, Madison and Red River formations. The Williston Basin is now one of the most actively drilled unconventional oil resource plays in the United States, with approximately 195 rigs drilling in the basin, including 184 in North Dakota and 11 in Montana, based on Anderson Reports’ weekly rig count dated January 3, 2013. A report issued by the United States Geological Survey in April 2008 classified these formations as the largest continuous oil accumulation ever assessed by it in the contiguous United States. 16


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    The Devonian-age Bakken formation is found within the Williston Basin underlying portions of North Dakota and Montana and is comprised of three lithologic members including the upper shale, middle Bakken and lower shale. The formation ranges up to 150 feet thick. The upper and lower shales are highly organic, thermally mature and over pressured and can act as both a source and reservoir for the oil. The middle Bakken, which varies in composition from a silty dolomite to shaley limestone or sand, also serves as a reservoir and is a critical component for commercial production. Generally, the Bakken formation is found at vertical depths of 8,500 to 11,500 feet. Based on our geologic interpretation of the Bakken formation, the evolution of completion techniques, our own drilling results and publicly available drilling results for other operators in the basin, we believe that a substantial portion of our Williston Basin acreage is prospective in the Bakken formation. The Three Forks formation, generally found immediately under the Bakken formation, has also proven to contain productive reservoir rock that may add incremental reserves to our existing leasehold positions. The Three Forks formation typically consists of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as Sanish sand. The Three Forks formation is an unconventional carbonate play. Based on our geologic interpretation of the Three Forks formation, the evolution of completion techniques, our own drilling results and publicly available drilling results for other operators in the basin, we believe that much of our Williston Basin acreage is prospective in the Three Forks formation. Our total leasehold position in the Williston Basin as of December 31, 2012 consisted of 335,383 net acres. Our estimated net proved reserves in the Williston Basin were 143.3 MMBoe at December 31, 2012. Of our estimated net proved reserves in the Williston Basin, approximately 70.0 MMBoe were proved developed reserves, which are comprised of a combination of wells drilled to conventional reservoirs, Bakken wells drilled with older completion techniques and Bakken and Three Forks wells drilled with completion techniques similar to those we currently employ. Based on our results to date, we estimate that the Bakken and Three Forks wells drilled with more recent completion techniques will achieve estimated ultimate recovery rates that will in many cases more than double the ultimate recovery rates we expect from the Bakken wells with older completion techniques. Based on publicly available information for other operators in the basin, we believe this trend towards higher recovery rates is generally consistent across the basin. Of our estimated net proved reserves, 73.3 MMBoe were proved undeveloped reserves, all of which consisted of Bakken and Three Forks wells to be drilled with more recent completion techniques. We expect that all of our identified drilling locations in each of our project areas will be drilled and completed using completion techniques similar to those we currently employ. As of December 31, 2012, we had a total of 263.6 net operated and non-operated producing wells and 227.8 net operated producing wells in the Williston Basin. We had average daily production of 22,469 net Boe/d for the year ended December 31, 2012 in the Williston Basin. During 2012, our Bakken and Three Forks wells produced a daily average of 21,766 net Boe/d with 216.2 net producing wells on December 31, 2012. Accordingly, our 216.2 net Bakken and Three Forks wells were responsible for 97% of our average daily production during 2012. As of December 31, 2012, our working interest for all producing wells averaged 37% and in the wells we operate was approximately 82%. As of December 31, 2012, we were drilling or completing 69 gross (25.6 net) wells in the Williston Basin. We participated in 231 gross (105.6 net) wells that were completed and brought on production during 2012. Currently, we estimate our capital expenditures for 2013 will be $1,020 million, which includes completing 128 gross (92.5 net) horizontal operated wells, participating in 10.9 net non-operated wells that are expected to be completed and brought on production, construction of infrastructure to support production and leasehold acquisitions. Since most of this capital is expected to be spent on horizontal drilling in the Bakken and Three Forks formations, we expect that the proportion of our production from these formations will grow in the future. Our Williston Basin activities are evaluated in three primary areas of operations: West Williston, East Nesson and Sanish. 17


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    West Williston We control 208,062 net acres in the West Williston project area, primarily in Williams and McKenzie counties in North Dakota and Roosevelt and Richland counties in Montana. We had average daily production of 15,263 net Boe/d for the year ended December 31, 2012, 95% of which was produced from the Bakken and Three Forks formations and the remainder from other conventional formations. As of December 31, 2012, we had an average working interest of 57% and operated 94% of our 176.2 net producing wells in the West Williston project area. As of December 31, 2012, we operated 97% of our 128.8 net producing Bakken and Three Forks wells in the West Williston project area. During the year ended December 31, 2012, our total completions were 94 gross (67.4 net) horizontal Bakken and Three Forks wells in the West Williston project area. As of December 31, 2012, we were participating in drilling or completion of 29 gross (16.3 net) wells in this project area. We have budgeted $520 million in capital expenditures in the West Williston project area in 2013 for the completion of 75 gross (55.3 net) operated wells and 2.9 net non-operated wells. East Nesson We control 118,943 net acres in the East Nesson project area, primarily in Mountrail and Burke counties in North Dakota. We had average daily production of 4,936 net Boe/d for the year ended December 31, 2012, all of which was produced from the Bakken and Three Forks formations. As of December 31, 2012, we had an average working interest of 47% and operated 91% of our 67.5 net producing wells in the East Nesson project area, all of which are producing out of the Bakken and Three Forks formations. During the year ended December 31, 2012, our total completions were 54 gross (31.4 net) horizontal Bakken and Three Forks wells in the East Nesson project area. As of December 31, 2012, we were participating in the drilling or completion of 24 gross (8.4 net) wells in this project area. We have budgeted $329 million in capital expenditures in the East Nesson project area in 2013 for the completion of 53 gross (37.2 net) operated wells and 2.3 net non-operated wells. Sanish We have 8,378 net acres in the Sanish project area, all of which are located in Mountrail County in North Dakota. We had average daily production of 2,270 net Boe/d for the year ended December 31, 2012, all of which was produced from the Bakken and Three Forks formations. As of December 31, 2012, we had an average working interest of 8% in our 19.9 net wells in the Sanish project area. Our properties in this project area are entirely operated by other operators, the largest of which are Whiting Petroleum Corporation and Fidelity Exploration. During the year ended December 31, 2012, our total completions were 83 gross (6.8 net) horizontal Bakken and Three Forks wells in the Sanish project area. As of December 31, 2012, we were participating in the drilling or completion of 16 gross (0.9 net) wells in this project area. We have budgeted $48 million in capital expenditures in the Sanish project area in 2013 for the completion of 5.8 net non-operated wells. Marketing, transportation and major customers The Williston Basin crude oil transportation and refining infrastructure has grown substantially in recent years, largely in response to drilling activity in the Bakken formation. In December 2012, oil production in North Dakota was approximately 769,000 barrels per day compared to approximately 535,000 barrels per day in December 2011. According to a presentation from the North Dakota Pipeline Authority dated January 11, 2013, there were approximately 463,000 barrels per day of crude oil pipeline transportation capacity in the Williston Basin as of December 31, 2012. In addition, approximately 670,000 barrels per day of specifically dedicated railcar transportation capacity has been placed into service as of December 31, 2012. In 2012, we began selling a 18


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    significant amount of our crude oil production from our West Williston project area through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. As of December 31, 2012, we flowed approximately 60% of our gross operated oil production through these gathering systems. We will continue to implement wellhead gathering of crude oil in 2013 with the implementation of gathering connections in our East Nesson project area, which we expect will increase the gross operated oil production that will flow on these systems to over 80% by mid-year 2013. Recent expansion of both rail and pipeline facilities has reduced the previous constraint on oil transportation out of the Williston Basin and improved netback pricing received at the lease. However, oil from Canada has put pressure on the existing pipeline infrastructure from the Williston Basin that terminates at Midwest refineries. In addition, although there were 670,000 barrels per day of railcar transportation capacity in place as of December 31, 2012, these railcar facilities are not yet running at nameplate capacity due to initial commissioning, limited crude oil supply and limited availability of railcars. We believe the operators of these railcar facilities have railcars on order and expect utilization on these facilities to continue to increase substantially during 2013. For a discussion of the potential risks to our business that could result from transportation and refining infrastructure constraints in the Williston Basin, please see “Item 1A. Risk Factors— Risks related to the oil and natural gas industry and our business—Insufficient transportation or refining capacity in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.” We principally sell our oil and natural gas production to refiners, marketers and other purchasers that have access to nearby pipeline and rail facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production” and “Risk Factors—Risks related to the oil and natural gas industry and our business—Insufficient transportation or refining capacity in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.” In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows. For the year ended December 31, 2012, sales to Musket Corporation accounted for approximately 10% of our total sales. For the year ended December 31, 2011, sales to Texon L.P., Plains All American Pipeline, L.P. and Enserco Energy Inc. accounted for approximately 18%, 16% and 15%, respectively, of our total sales. For the year ended December 31, 2010, sales to Plains All American Pipeline, L.P., Texon L.P. and Whiting Petroleum Corporation accounted for approximately 28%, 19% and 11%, respectively, of our total sales. No other purchasers accounted for more than 10% of our total oil and natural gas sales for the years ended December 31, 2012, 2011 and 2010. We believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as there are a number of alternative crude oil and natural gas purchasers in our project areas. As of December 31, 2012, we sold a substantial majority of our oil and condensate through bulk sales from delivery points on crude oil gathering systems or directly at the wellhead to a variety of purchasers at prevailing market prices under short-term contracts that normally provide for us to receive a market-based price, which incorporates regional differentials that include, but are not limited to, transportation costs and adjustments for product quality. Crude oil produced and sold in the Williston Basin has historically sold at a discount to the price quoted for NYMEX West Texas Intermediate (“WTI”) crude oil due to transportation costs and takeaway capacity. In the past, there have been periods when this discount has substantially increased due to the production 19


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    of oil in the area increasing to a point that it temporarily surpasses the available pipeline transportation, rail transportation and refining capacity in the area. In the first half of 2012, price differentials were at or above the historical average discount range of 10% to 15% to the price quoted for WTI crude oil due to production growth in the Williston Basin combined with refinery and transportation constraints. In the third quarter of 2012, differentials began to narrow, primarily due to the transportation capacity additions discussed above outpacing production growth. In the fourth quarter of 2012, these price differentials continued to narrow and at some points crude oil produced in the Williston Basin sold at a premium to WTI as a result of additional transportation capacity additions which access East and West Coast refineries. Since most of our oil and natural gas production is sold under market-based or spot market contracts, the revenues generated by our operations are highly dependent upon the prices of and demand for oil and natural gas. The price we receive for our oil and natural gas production depends upon numerous factors beyond our control, including but not limited to seasonality, weather, competition, availability of transportation and gathering capabilities, the condition of the United States economy, foreign imports, political conditions in other oil- producing and natural gas-producing regions, the actions of the Organization of Petroleum Exporting Countries, or OPEC, and domestic government regulation, legislation and policies. Please see “Item 1A. Risk Factors— Risks related to the oil and natural gas industry and our business—A substantial or extended decline in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.” Furthermore, a decrease in the price of oil and natural gas could have an adverse effect on the carrying value of our proved reserves and on our revenues, profitability and cash flows. Please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—If oil and natural gas prices decrease, we may be required to take write- downs of the carrying values of our oil and natural gas properties.” Market, economic, transportation and regulatory factors may in the future materially affect our ability to market our oil or natural gas production. Please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.” Competition The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas companies in all areas of operation, including the acquisition of leasing options on oil and natural gas properties to the exploration and development of those properties. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do. Such companies may be able to pay more for lease options on oil and natural gas properties and exploratory locations and to define, evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.” Title to properties As is customary in the oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a 20


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    property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with general industry standards. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our revolving credit facility, liens for current taxes and other burdens, which we believe do not materially interfere with the use or affect our carrying value of the properties. Please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—We may incur losses as a result of title defects in the properties in which we invest.” Seasonality Winter weather conditions and lease stipulations can limit or temporarily halt our drilling and producing activities and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations. Regulation of the oil and natural gas industry Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations are frequently amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective. Regulation of transportation of oil Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil 21


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    pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost of service filing. Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs. Most recently, on December 16, 2010, the FERC established a new price index for the five-year period beginning July 1, 2011. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is generally governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors. Regulation of transportation and sales of natural gas Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993. FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry. In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. 22


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    The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC under Order No. 637 will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers. The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission (“CFTC”) and the Federal Trade Commission (“FTC”). Please see below the discussion of “Other federal laws and regulations affecting our industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous calendar year. Order No. 704 requires certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. Please see below the discussion of “Other federal laws and regulations affecting our industry—FERC Market Transparency Rules.” Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case by case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Regulation of production The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. 23


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    The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations. Other federal laws and regulations affecting our industry Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (“EPAct 2005”). EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1 million per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1 million per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act, practice or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non- jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. FERC Market Transparency Rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the FTC issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from: (a) knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1 million per day per violation, in addition to any applicable penalty under the Federal Trade Commission Act. 24


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    North Dakota Industrial Commission oil and gas rule changes. The North Dakota Industrial Commission has adopted more stringent rule changes to its existing oil and gas regulations. The rules became effective on April 1, 2012 and, among other things, impose relatively higher bonding amounts for the drilling of wells, severely restrict the discharge and storage of production wastes such as produced water, drilling mud, waste oil and other wastes in earthen pits, implement more stringent hydraulic fracturing requirements and require the provision of public disclosure on the national website, FracFocus.org, regarding chemicals used in the hydraulic fracturing process. Compliance with these recent rule changes by oil and natural gas exploration and production operators in general and us in particular increased our well costs during 2012, and we expect to continue to incur these increased costs in order to remain in compliance. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors. Environmental and occupational health and safety regulation Our exploration, development and production operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered species; require investigatory and remedial actions to mitigate pollution conditions; impose obligations to reclaim and abandon well sites and pits; and impose specific criteria addressing worker protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in federal or state environmental laws and regulations or reinterpretation of applicable enforcement policies that result in more stringent and costly well construction, drilling, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on our financial condition or results of operations, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. Hazardous substances and wastes The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a 25


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    “hazardous substance” into the environment. These classes of persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances. We are also subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation, disposal and cleanup of hazardous and nonhazardous solid wastes. Under the authority of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. RCRA currently exempts certain drilling fluids, produced waters and other wastes associated with exploration, development and production of oil and natural gas from regulation as hazardous wastes. These wastes, instead, are regulated under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. Repeal or modification of this RCRA exclusion or similar exemptions under state law could increase the amount of hazardous waste we are required to manage and dispose of and could cause us to incur increased operating costs, which could have a significant impact on us as well as the oil and natural gas industry in general. In addition, in the course of our operations, we generate ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons, hazardous substances and wastes may have been released on, under or from the properties owned or leased by us or on, under or from, other locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, certain of these properties have been operated by the third parties whose treatment and disposal or release of petroleum hydrocarbons, hazardous substances and wastes were not under our control. These properties and the substances disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial plugging or pit closure operations to prevent future contamination. Air emissions The federal Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of various air pollutants from many sources through air emissions standards, construction and operating permitting programs, and the imposition of other monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Obtaining permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, on August 16, 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air 26


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    Pollutants, or NESHAP, programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2013. We continually review new rules such as these to assess their impact on our operations. Compliance with new requirements could increase our costs of development and production, which costs could be significant. Climate change Based on findings made by the EPA in December 2009 that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the Earth’s atmosphere and other climatic changes, the EPA adopted regulations under existing provisions of the CAA that establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations. Water discharges The Federal Water Pollution Control Act, as amended (the “Clean Water Act”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of 27


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    the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The Oil Pollution Act of 1990, as amended (“OPA”), amends the Clean Water Act, and sets minimum standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels, offshore facilities and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States. Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. Recent North Dakota Industrial Commission rule changes effective April 1, 2012 severely restrict the discharge and storage of production wastes including produced water in earthen pits, which increases the likelihood that injection wells are used to dispose of appropriate waste streams. These injection wells are regulated by the federal Safe Drinking Water Act and analogous state laws. The underground injection well program under the Safe Drinking Water Act requires permits from the EPA or analogous state agency for disposal wells that we operate, establishes minimum standards for injection well operations and restricts the types and quantities of fluids that may be injected. While we believe that we are in substantial compliance with applicable disposal well requirements, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations, which costs could be significant. Hydraulic fracturing activities Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from unconventional formations, including shales. The process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and gas commissions, but the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nevertheless, 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. 28


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    In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms. To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would generally cover third-party claims directly related to hydraulic fracturing operations conducted by third parties and associated legal expenses in accordance with, and subject to, the terms of such policies. However, certain long term pollution and environmental risks are not fully insurable. Please see “Item 1A. Risk Factors—We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.” Endangered Species Act considerations The federal Endangered Species Act, as amended (“ESA”), may restrict exploration, development and production activities that may affect endangered and threatened species or their habitats. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States and prohibits the taking of endangered species. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on a listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. Operations on federal lands Performance of oil and gas exploration and production activities on federal lands, including Indian lands and lands administered by the federal Bureau of Land Management (“BLM”) are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs, to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made 29


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    available for public review and comment. Depending on any mitigation strategies recommended in such environmental assessments or environmental impact statements, we could incur added costs, which could be substantial, and be subject to delays or limitations in the scope of oil and natural gas projects. Employee health and safety We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety. Employees As of December 31, 2012, we employed 281 people. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services. Offices As of December 31, 2012, we leased 80,685 square feet of office space in Houston, Texas at 1001 Fannin Street, where our principal offices are located. The lease for our Houston office expires in September 2017. We also own field offices in Williston, North Dakota and Powers Lake, North Dakota. Available information We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov. Our common stock is listed and traded on the New York Stock Exchange under the symbol “OAS.” Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad Street, New York, New York 10005. We also make available on our website at http://www.oasispetroleum.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website, other than the documents listed below, is not incorporated by reference into this Annual Report on Form 10-K. 30


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    Item 1A. Risk Factors Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us. Risks related to the oil and natural gas industry and our business A substantial or extended decline in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments. The price we receive for our oil and, to a lesser extent, natural gas, heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following: • worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas; • the actions of OPEC; • the price and quantity of imports of foreign oil and natural gas; • political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America, China, India and Russia; • the level of global oil and natural gas exploration and production; • the level of global oil and natural gas inventories; • localized supply and demand fundamentals and regional, domestic and international transportation availability; • weather conditions and natural disasters; • domestic and foreign governmental regulations; • speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts; • price and availability of competitors’ supplies of oil and natural gas; • technological advances affecting energy consumption; and • the price and availability of alternative fuels. Substantially all of our production is sold to purchasers under short-term (less than twelve-month) contracts at market-based prices. Lower oil and natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. See “Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves.” Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our proved reserves. See also “The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves” below. 31


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    Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” below. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following: • shortages of or delays in obtaining equipment and qualified personnel; • facility or equipment malfunctions and/or failure; • unexpected operational events, including accidents; • pressure or irregularities in geological formations; • adverse weather conditions, such as blizzards, ice storms and floods; • reductions in oil and natural gas prices; • delays imposed by or resulting from compliance with regulatory requirements; • proximity to and capacity of transportation facilities; • title problems; and • limitations in the market for oil and natural gas. Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See “Item 1. Business—Our operations” for information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net revenues as of December 31, 2012, 2011 and 2010. In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by our independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant 32


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    variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. In addition, we may adjust estimates of net proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. The present value of future net revenues from our estimated net proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. You should not assume that the present value of future net revenues from our estimated net proved reserves is the current market value of our estimated net oil and natural gas reserves. In accordance with SEC requirements for the years ended December 31, 2012, 2011 and 2010, we based the estimated discounted future net revenues from our estimated net proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the- month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as: • actual prices we receive for oil and natural gas; • actual cost of development and production expenditures; • the amount and timing of actual production; and • changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from estimated net proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report on Form 10-K. Any significant future price changes will have a material effect on the quantity and present value of our estimated net proved reserves. The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis. Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations. Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful. Operations in the Bakken and the Three Forks formations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally 33


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    through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Bakken and Three Forks formations is limited. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate. We could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future. Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net oil and natural gas reserves. Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. We spent $1,148.6 million and $666.0 million related to capital expenditures for the years ended December 31, 2012 and 2011, respectively. Our capital expenditure budget for 2013 is approximately $1,020 million, with approximately $897 million allocated for drilling and completion operations. Since our IPO, our capital expenditures have been financed with proceeds from our IPO, net cash provided by operating activities and proceeds from our $1.2 billion of senior unsecured notes. DeGolyer and MacNaughton projects that we will incur capital costs (including abandonment obligations) in excess of $1,324 million over the next four years to develop the proved undeveloped reserves in the Williston Basin covered by its December 31, 2012 reserve report. Because these costs cover less than 25% of our net primary drilling locations, we will be required to generate or raise multiples of this amount of capital to develop all of our potential drilling locations should we elect to do so. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A significant improvement in product prices could result in an increase in our capital expenditures. We intend to finance our future capital expenditures primarily through net proceeds from our previous issuances of senior unsecured notes, cash flows provided by operating activities, and borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of additional debt or equity securities or the sale of non-strategic assets. The issuance of additional debt or equity may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under our revolving credit facility will be automatically reduced by an amount equal to 25% of the aggregate principal amount of such debt securities. Our cash flows provided by operating activities and access to capital are subject to a number of variables, including: • our estimated net proved reserves; • the level of oil and natural gas we are able to produce from existing wells and new projected wells; 34


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    • the prices at which our oil and natural gas are sold; • the costs of developing and producing our oil and natural gas production; • our ability to acquire, locate and produce new reserves; • the ability and willingness of our banks to lend; and • our ability to access the equity and debt capital markets. If the borrowing base under our revolving credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations. If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties. We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount available under our revolving credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our revolving credit facility and our results of operations for the periods in which such charges are taken. No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2012, 2011 and 2010. We will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets. We expect that we will not be the operator on approximately 38% of our identified gross drilling locations (approximately 9% of our identified net drilling locations). As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including: • the timing and amount of capital expenditures; • the operator’s expertise and financial resources; • approval of other participants in drilling wells; • selection of technology; and • the rate of production of reserves, if any. This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition. 35


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    All of our producing properties and operations are located in the Williston Basin region, making us vulnerable to risks associated with operating in one major geographic area. As of December 31, 2012, 100% of our proved reserves and production were located in the Williston Basin in northeastern Montana and northwestern North Dakota. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. Our business depends on oil and natural gas gathering and transportation facilities, most of which are owned by third parties. The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. See also “Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production” and “Insufficient transportation or refining capacity in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices.” We generally do not purchase firm transportation on third party pipeline facilities, and therefore, the transportation of our production can be interrupted by other customers that have firm arrangements. The disruption of third-party facilities due to maintenance, weather or other interruptions of service could also negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored. A total shut-in of our production could materially affect us due to a resulting lack of cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow. Insufficient transportation or refining capacity in the Williston Basin could cause significant fluctuations in our realized oil and natural gas prices. The Williston Basin crude oil business environment has historically been characterized by periods when oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for WTI crude oil. Although additional Williston Basin transportation takeaway capacity was added in 2011 and 2012, production also increased due to the elevated drilling activity in these years. The increased production coupled with delays in rail car arrivals and commissioning of rail loading facilities caused price differentials at times to be at the high-end of the historical average range of approximately 10% to 15% of the WTI crude oil index price in the first half of 2012. During the second half of 2012, differentials improved due to expanding rail infrastructure and pipeline expansions coming online. On barrels that are transported over pipelines to either Clearbrook, Minnesota or Guernsey, Wyoming, our realized price for crude oil is generally the quoted price for Bakken crude oil less transportation costs from the point where the crude oil is sold. 36


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    The development of our proved undeveloped reserves in the Williston Basin and other areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced. Approximately 51% of our estimated net proved reserves were classified as proved undeveloped as of December 31, 2012. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves. Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations. Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our estimated net proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production. Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. If our production becomes shut- in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market. We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks. We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of: • environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gas or other pollutants into the environment; • abnormally pressured formations; • shortages of, or delays in, obtaining water for hydraulic fracturing activities; 37


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    • mechanical difficulties, such as stuck oilfield drilling and service tools and casing failure; • personal injuries and death; and • natural disasters. Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of: • injury or loss of life; • damage to and destruction of property, natural resources and equipment; • pollution and other environmental damage; • regulatory investigations and penalties; • suspension of our operations; and • repair and remediation costs. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations. We have incurred losses in prior years and may do so again in the future. For the years ended December 31, 2012 and 2011, we had net income of $153.4 million and $79.4 million, respectively. However, for the year ended December 31, 2010, we incurred a net loss of $29.7 million. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures, including planned capital expenditures for 2013 of approximately $1,020 million. The uncertainty and risks described in this Annual Report on Form 10-K may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future. Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities. We describe some of our drilling locations and our plans to explore those drilling locations in this Annual Report on Form 10-K. Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Williston Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive. 38


  • Page 45

    Our potential drilling location inventories are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations. Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities. Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, 2012, we had leases representing 22,461 net acres expiring in 2013, 9,970 net acres expiring in 2014 and 35,011 net acres expiring in 2015. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business. During each of the years ended December 31, 2012 and 2011, we recorded non-cash impairment charges of $3.6 million, and during the year ended December 31, 2010, we recorded non-cash impairment charges of $12.0 million on our unproved properties due to expiring leases and periodic assessments of our unproved properties. 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 that are applicable to our operations including the acquisition of a permit before conducting drilling or underground injection activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from 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 actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing 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 waste water 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 39


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    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 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, may also have the right to 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 damage. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our financial condition or results of well drilling, construction, completion on water management activities or operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste 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. Failure to comply with federal, state and local laws could adversely affect our ability to produce, gather and transport our oil and natural gas and may result in substantial penalties. Our operations are substantially affected by federal, state and local laws and regulations, particularly as they relate to the regulation of oil and natural gas production and transportation. These laws and regulations include regulation of oil and natural gas exploration and production and related operations, including a variety of activities related to the drilling of wells, the interstate transportation of oil and natural gas by federal agencies such as the FERC, as well as state agencies. In addition, federal laws prohibit market manipulation in connection with the purchase or sale of oil and/or natural gas. Failure to comply with federal, state and local laws could adversely affect our ability to produce, gather and transport our oil and natural gas and may result in substantial penalties. Please see “Other federal laws and regulations affecting our industry.” Climate change legislation and regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. Based on findings by the EPA in December 2009 that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the Earth’s atmosphere and other climatic changes, the EPA adopted regulations under existing provisions of the CAA that establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas production facilities on an annual basis, which includes certain of our operations. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. The adoption and implementation of any legislation or regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. 40


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    Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations. 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. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/ or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. 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. In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms. Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel. Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and 41


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    exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business. The loss of senior management or technical personnel could adversely affect our operations. To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Thomas B. Nusz, our Chairman, President and Chief Executive Officer, and Taylor L. Reid, our Executive Vice President and Chief Operating Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate. Oil and natural gas operations in the Williston Basin are adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Severe winter weather conditions limit and may temporarily halt our ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Our derivative activities could result in financial losses or could reduce our income. To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments. Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when: • production is less than the volume covered by the derivative instruments; • the counterparty to the derivative instrument defaults on its contract obligations; or • there is an increase in the differential between the underlying price in the derivative instrument and actual price received. In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements. 42


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    The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate and other risks associated with our business. On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012, although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” The Dodd-Frank Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows. Increased costs of capital could adversely affect our business. Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results. We may not be able to generate enough cash flow to meet our debt obligations. We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry 43


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    factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as: • selling assets; • reducing or delaying capital investments; • seeking to raise additional capital; or • refinancing or restructuring our debt. If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on our senior unsecured notes. If amounts outstanding under our revolving credit facility or our senior unsecured notes were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and capital resources.” Our revolving credit facility and the indentures governing our senior unsecured notes all contain operating and financial restrictions that may restrict our business and financing activities. Our revolving credit facility and the indentures governing our senior unsecured notes contain a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things: • sell assets, including equity interests in our subsidiaries; • pay distributions on, redeem or repurchase our common stock or redeem or repurchase our subordinated debt; • make investments; • incur or guarantee additional indebtedness or issue preferred stock; • create or incur certain liens; • make certain acquisitions and investments; • redeem or prepay other debt; • enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; • consolidate, merge or transfer all or substantially all of our assets; • engage in transactions with affiliates; • create unrestricted subsidiaries; • enter into sale and leaseback transactions; and • engage in certain business activities. As a result of these covenants, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs. 44

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