Oasis Petroleum Inc.
Annual Report 2015

Plain-text annual report

Morningstar® Document Research℠ FORM 10-KOasis Petroleum Inc. - OASFiled: February 25, 2016 (period: December 31, 2015)Annual report with a comprehensive overview of the companyThe information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The userassumes all risks for any damages or losses arising from any use of this information, except to the extent such damages or losses cannot belimited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsUNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 _______________________________________FORM 10-K _______________________________________ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2015OR¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934Commission file number: 1-34776_______________________________________ Oasis Petroleum Inc.(Exact name of registrant as specified in its charter)_______________________________________Delaware 80-0554627(State or other jurisdiction ofincorporation or organization) (I.R.S. EmployerIdentification 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 ý 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 ýIndicate 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 of1934 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 filingrequirements for the past 90 days. Yes ý No ¨Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data Filerequired 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 shorterperiod that the registrant was required to submit and post such files). Yes ý 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, tothe 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 tothis Form 10-K. ýIndicate 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 filerýAccelerated 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 ýAggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the commonequity 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 secondfiscal quarter: $2,205,627,149Number of shares of registrant’s common stock outstanding as of February 18, 2016: 180,556,502Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results._______________________________________ Documents Incorporated By Reference:Portions of the registrant’s definitive proxy statement for its 2016 Annual Meeting of Stockholders, which will be filed with the Securities andExchange Commission within 120 days of December 31, 2015, are incorporated by reference into Part III of this report for the year ended December 31, 2015.Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOASIS PETROLEUM INC.FORM 10-KFOR THE YEAR ENDED DECEMBER 31, 2015TABLE OF CONTENTS Part I – Item 1. Business4Item 1A. Risk Factors27Item 1B. Unresolved Staff Comments43Item 2. Properties43Item 3. Legal Proceedings43Item 4. Mine Safety Disclosures43 Part II – Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities44Item 6. Selected Financial Data45Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations50Item 7A. Quantitative and Qualitative Disclosures about Market Risk69Item 8. Financial Statements and Supplementary Data71Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure118Item 9A. Controls and Procedures118Item 9B. Other Information119 Part III – Item 10. Directors, Executive Officers and Corporate Governance120Item 11. Executive Compensation120Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters120Item 13. Certain Relationships and Related Transactions, and Director Independence120Item 14. Principal Accountant Fees and Services120 Part IV – Item 15. Exhibits, Financial Statement Schedules1212Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTSThis Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, asamended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-lookingstatements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical factincluded 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 identifyforward-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;•timing and amount of future production of oil and natural gas;•drilling and completion of wells;•estimated inventory of wells remaining to be drilled and completed;•costs of exploiting and developing our properties and conducting other operations;•availability of drilling, completion and production equipment and materials;•availability of qualified personnel;•owning and operating a well services company;•owning, operating and developing a midstream company;•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;•property acquisitions;•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness;•the amount, nature and timing of capital expenditures;•availability and terms of capital;•our financial strategy, budget, projections, execution of business plan and operating results;•cash flows and liquidity;•oil and natural gas realized prices;•general economic conditions;•operating environment, including inclement weather conditions;•effectiveness of risk management activities;•competition in the oil and natural gas industry;•counterparty credit risk;•environmental liabilities;•governmental regulation and the taxation of the oil and natural gas industry;•developments in oil-producing and natural gas-producing countries;•technology;•uncertainty regarding future operating results; and•plans, objectives, expectations and intentions contained in this report that are not historical.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 revisethese statements unless required by securities law, and you should not place undue reliance on these forward-looking statements. Although we believe thatour plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report on Form 10-K arereasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actualresults to differ materially from our expectations under “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Conditionand Results of Operations” and elsewhere in this Annual Report on Form 10-K. These cautionary statements qualify all forward-looking statementsattributable to us or persons acting on our behalf.3Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPART IItem 1. BusinessOverviewOasis Petroleum Inc. (together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) was originally formed in 2007 and was incorporatedpursuant to the laws of the State of Delaware in 2010. We are an independent exploration and production company focused on the acquisition anddevelopment of unconventional oil and natural gas resources in the North Dakota and Montana regions of the Williston Basin. Oasis Petroleum NorthAmerica LLC (“OPNA”) conducts our exploration and production activities and owns our proved and unproved oil and natural gas properties. We alsooperate a well services business through Oasis Well Services LLC (“OWS”) and a midstream services business through Oasis Midstream Services LLC(“OMS”).As of December 31, 2015, we have accumulated 484,745 net leasehold acres in the Williston Basin, of which approximately 91% is held by production. Weare currently exploiting significant resource potential from the Bakken and Three Forks formations, which are present across a substantial portion of ouracreage. We believe the location, size and concentration of our acreage create an opportunity for us to achieve cost, recovery and production efficienciesthrough the development of our project inventory. Our management team has a proven track record in identifying, acquiring and executing large, repeatabledevelopment drilling programs, which we refer to as “resource conversion” opportunities, and has substantial Williston Basin experience.In 2015, we completed and placed on production 80 gross operated wells in the Williston Basin and had average daily production of 50,477 Boe per day. Asof December 31, 2015, we had 1,095 gross (595.5 net) producing wells in the Bakken and Three Forks formations. DeGolyer and MacNaughton, ourindependent reserve engineers, estimated our net proved reserves to be 218.2 MMBoe as of December 31, 2015, of which 68% were classified as proveddeveloped and of which 85% were oil.Our business strategyOur goal is to enhance value by investing capital to build reserves, production and cash flows at attractive rates of return through the following strategies:•Efficiently develop our Williston Basin leasehold position. We are developing our acreage position to maximize the value of our resource potential,while maintaining flexibility to preserve future value when oil prices are low. During 2014, when the NYMEX West Texas Intermediate crude oilindex price (“WTI”) averaged $92.07 per barrel throughout the year, we completed and brought on production 195 gross (147.4 net) operated Bakkenand Three Forks wells in the Williston Basin. During 2015, when WTI averaged $48.75 per barrel, we completed and brought on production 80 gross(62.4 net) operated Bakken and Three Forks wells. As of December 31, 2015, we had 85 gross operated wells waiting on completion in the Bakken andThree Forks formations. Our 2016 capital plan, which was finalized when WTI for 2016 was projected to average approximately $35.00 per barrel,contemplates operating two rigs and completing and placing on production approximately 46 gross (28.6 net) operated wells. We have the ability toincrease or decrease the number of wells drilled and the number of wells completed during 2016 based on market conditions and program results.•Enhance returns by focusing on operational and cost efficiencies. Our management team is focused on continuous improvement of our operations andhas significant experience in successfully operating cost-efficient development programs. We believe the magnitude and concentration of our acreagewithin the Williston Basin, particularly in the core of the play, has and will continue to provide us with the opportunity to capture economies of scale,including the ability to drill multiple wells from a single drilling pad into multiple formations, utilizing centralized production and oil, gas and waterfluid handling facilities and infrastructure, and reducing the time and cost of rig mobilization. In addition, we expect OWS and OMS to continue toprovide operational synergies going forward compared to third party providers.•Adopt and employ leading drilling and completion techniques. Our team is focused on enhancing our drilling and completion techniques tomaximize overall well economics. We have significantly reduced the number of days that it takes to drill wells, and we believe completion techniqueshave significantly evolved over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well. Highintensity completion techniques continue to deliver production performance greater than prior completion techniques. We continuously evaluate ourinternal drilling and completion results and monitor the results of other operators to improve our operating practices. This continued evolution mayenhance our initial production rates, increase ultimate recovery factors, lower well capital costs and improve rates of return on invested capital.•Maintain financial flexibility. Based on current market conditions, we have a strong liquidity position. In February 2016, we completed a publicequity offering of 39,100,000 shares, raising $182.9 million of net proceeds to be used for general corporate purposes and to fund a portion of our2016 capital expenditures. We have no near-term debt maturities,4Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsand, in April 2015, we amended our revolving credit facility to extend its maturity date from April 2018 to April 2020, provided that our 7.25% seniorunsecured notes due 2019 are retired or refinanced 90 days prior to their maturity. In October 2015, we successfully completed consent solicitationsrespecting amendments to the indentures governing certain of our senior unsecured notes, which amendments allow us to incur secured credit facilitiesindebtedness up to the amount of our borrowing base at the time of the incurrence, but not to exceed $1,525.0 million. In February 2016, our springborrowing base redetermination was completed, resulting in a borrowing base decrease from $1,525.0 million to $1,150.0 million. As of December 31,2015, we had $138.0 million of borrowings and $5.2 million of outstanding letters of credit under our revolving credit facility and $1,199.4 million ofpro forma liquidity available, including adjustments for the new borrowing base and the net proceeds from our public equity offering in February2016. Our liquidity position, along with internally generated cash flows from operations and settlements from our derivative contracts in 2016, willprovide continued financial flexibility as we actively manage the pace of development on our acreage position in the Williston Basin. We alsocurrently believe we have access to the public and private capital markets, and we intend to maintain a balanced capital structure by prudently raisingproceeds from future offerings as additional capital needs arise. We are also continuing to evaluate options to monetize certain assets in our portfolio,which could result in increased liquidity and lower leverage.•Pursue strategic acquisitions with significant resource potential. As opportunities arise, we intend to identify and acquire additional acreage andproducing assets in the Williston Basin to supplement our existing operations. Going forward, we may selectively target additional basins that wouldallow us to employ our resource conversion strategy on large undeveloped acreage positions similar to what we have accumulated in the WillistonBasin.Our competitive strengthsWe 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. We believe our acreage is one of the largestconcentrated leasehold positions that is prospective in the Bakken and Three Forks formations. As of December 31, 2015, substantially all of our484,745 net leasehold acres in the Williston Basin were highly prospective in the Bakken and Three Forks formations, and 85% of our 218.2 MMBoeestimated net proved reserves in this area were comprised of oil. In addition, we have 442,292 net acres held by production as of December 31, 2015. In2015, we increased per well capital efficiency through our focused development efforts in our core acreage and improved operational efficiency,coupled with lower service costs from third-party vendors and OWS. In 2016, we will continue to concentrate our drilling and completion activities inour core acreage, which is located in the deepest part of the Williston Basin.•Large, multi-year project inventory. We believe we have a large inventory of potential drilling locations that we have not yet drilled, a majority ofwhich are operated by us. We plan to slow the pace of completions again in 2016 to 46 gross (28.6 net) operated wells in the Williston Basin in orderto maintain financial flexibility and preserve the value of our inventory.•Management team with proven operating and acquisition skills. Our senior management team has extensive expertise in the oil and gas industry. Oursenior technical team has an average of more than 25 years of industry experience, including experience in multiple North American resource plays aswell as experience in international basins. We believe our management and technical team is one of our principal competitive strengths relative to ourindustry peers due to our team’s proven track record in identification, acquisition and execution of resource conversion opportunities. In addition, ourtechnical team possesses substantial expertise in horizontal drilling techniques and managing and acquiring large development programs.•Incentivized management team. In 2015, an average of 57% of our executive officers’ overall compensation was in long-term equity-based incentiveawards, and such officers owned 2.5% of our outstanding common stock as of December 31, 2015. We believe our executive officers’ ownershipinterest 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 leaseholdposition comprised primarily of properties that we expect to operate. As of December 31, 2015, 97% of our estimated net proved reserves wereattributable to properties that we expect to operate, and our average working interest in our 2016 operated completion plan is expected to be 66%.Approximately 92% of our 2016 drilling and completion capital expenditure budget is related to operated wells. Controlling operations will allow usto dictate the pace of development and better manage the costs, type and timing of exploration and development activities. We believe thatmaintaining operational control over the majority of our acreage will allow us to better pursue our strategies of enhancing returns through operationaland cost efficiencies and maximizing hydrocarbon recovery through continuous improvement of drilling and completion techniques. We are alsobetter able to control infrastructure5Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsinvestment to drive down operating costs, optimize oil price realizations and increase the monetization of gas production.Our operationsEstimated net proved reservesThe table below summarizes our estimated net proved reserves and related PV-10 at December 31, 2015, 2014 and 2013 based on reports prepared byDeGolyer and MacNaughton, our independent reserve engineers. In preparing its reports, DeGolyer and MacNaughton evaluated 100% of the reserves anddiscounted values at December 31, 2015, 2014 and 2013 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 and related future net revenues, PV-10 andStandardized Measure do not include probable or possible reserves and were determined using the preceding twelve months’ unweighted arithmetic averageof the first-day-of-the-month index prices for oil and natural gas, which were held constant throughout the life of the properties. The unweighted arithmeticaverage first-day-of-the-month prices for the prior twelve months were $50.16/Bbl for oil and $2.63/MMBtu for natural gas, $95.28/Bbl for oil and$4.35/MMBtu for natural gas and $96.96/Bbl for oil and $3.66/MMBtu for natural gas for the years ended December 31, 2015, 2014 and 2013, respectively.These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affectingthe price received at the wellhead. The information in the following table does not give any effect to or reflect our commodity derivatives. Future operatingcosts, production taxes and capital costs were based on current costs as of each year-end. For a definition of proved reserves under the SEC rules, please seethe “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, 2015 2014 2013Reserves Data: Estimated proved reserves: Oil (MMBbls)184.9 235.4 198.6Natural gas (Bcf)199.8 220.1 176.0Total estimated proved reserves (MMBoe)218.2 272.1 227.9Percent oil85% 87% 87%Estimated proved developed reserves: Oil (MMBbls)127.4 127.3 106.8Natural gas (Bcf)120.8 114.0 92.2Total estimated proved developed reserves (MMBoe)147.6 146.3 122.1Percent proved developed68% 54% 54%Estimated proved undeveloped reserves: Oil (MMBbls)57.5 108.1 91.8Natural gas (Bcf)79.0 106.1 83.8Total estimated proved undeveloped reserves (MMBoe)70.7 125.7 105.8PV-10 (in millions)(1)$2,022.7 $5,481.4 $5,486.9Standardized Measure (in millions)(2)$1,914.3 $3,981.7 $3,727.6__________________ (1)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable financial measure underaccounting principles generally accepted in the United States of America (“GAAP”), because it does not include the effect of income taxes ondiscounted future net cash flows. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gasreserves. 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 regardto the specific tax characteristics of such entities. See “Reconciliation of PV-10 to Standardized Measure” below.(2)Standardized Measure represents the present value of estimated future net cash flows from proved oil and natural gas reserves, less estimated futuredevelopment, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cashflows.6Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsEstimated net proved reserves at December 31, 2015 were 218.2 MMBoe, a 20% decrease from estimated net proved reserves of 272.1 MMBoe atDecember 31, 2014 primarily due to revisions related to lower commodity prices, partially offset by our 2015 drilling program and well completions as wellas lower estimated future operating and capital costs. Our proved developed reserves increased 1.3 MMBoe, or 1%, to 147.6 MMBoe for the year endedDecember 31, 2015 from 146.3 MMBoe for the year ended December 31, 2014, primarily due to our 2015 drilling program, including the completion of 80gross (62.4 net) operated wells, partially offset by production and higher abandonment rates resulting from lower commodity price assumptions. Our provedundeveloped reserves decreased to 70.7 MMBoe for the year ended December 31, 2015 from 125.7 MMBoe for the year ended December 31, 2014 due toincreases from our 2015 drilling program offset by the removal of proved undeveloped reserves that are not economic at the lower oil price or are no longeraligned with our anticipated five-year drilling plan. Estimated net proved reserves at December 31, 2014 were 272.1 MMBoe, a 19% increase from estimated net proved reserves of 227.9 MMBoe atDecember 31, 2013 primarily as a result of our 2014 drilling program and well completions, partially offset by the sale of certain non-operated properties inand around our Sanish position (the “Sanish Divestiture”) during the year ended December 31, 2014. Our proved developed reserves increased 24.2 MMBoe,or 20%, to 146.3 MMBoe for the year ended December 31, 2014 from 122.1 MMBoe for the year ended December 31, 2013, primarily due to our 2014drilling program, including the completion of 195 gross (147.4 net) operated wells. Our proved undeveloped reserves increased to 125.7 MMBoe for the yearended December 31, 2014 from 105.8 MMBoe for the year ended December 31, 2013, primarily due to our 2014 drilling program and changes to align ourproved undeveloped reserves with our anticipated five-year drilling plan.Reconciliation of PV-10 to Standardized MeasurePV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 isa 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 discountedfuture net cash flows at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevantand useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into accountfuture 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 whenassessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure ofdiscounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fairvalue 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, 2015, 2014 and2013: At December 31, 2015 2014 2013 (In millions) PV-10$2,022.7 $5,481.4 $5,486.9Present value of future income taxes discounted at 10%108.4 1,499.7 1,759.3Standardized Measure of discounted future net cash flows$1,914.3 $3,981.7 $3,727.6The PV-10 of our estimated net proved reserves at December 31, 2015 was $2,022.7 million, a 63% decrease from PV-10 of $5,481.4 million at December 31,2014. This decrease was primarily due to lower commodity price assumptions and a decrease in reserves, partially offset by a reduction in future developmentcosts year over year.Estimated future net revenuesFuture net revenues represent projected revenues from the sale of our estimated net proved reserves (excluding derivative contracts) net of production anddevelopment costs (including operating expenses and production taxes). The following table sets forth the estimated future net revenues from provedreserves, the present value of those net revenues (PV-10) and the expected benchmark prices used in projecting net revenues at December 31, 2015, 2014 and2013: 7Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents At December 31, 2015 2014 2013 (In millions, except price data)Future net revenues$3,827.9 $11,999.3 $11,685.6Present value of future net revenues: Before income tax (PV-10)2,022.7 5,481.4 5,486.9After income tax (Standardized Measure)1,914.3 3,981.7 3,727.6Benchmark oil price ($/Bbl)(1)$50.16 $95.28 $96.96__________________ (1)Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil andnatural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmeticaverage first-day-of-the-month prices for the prior twelve months were $50.16/Bbl for oil and $2.63/MMBtu for natural gas, $95.28/Bbl for oil and$4.35/MMBtu for natural gas and $96.96/Bbl for oil and $3.66/MMBtu for natural gas for the years ended December 31, 2015, 2014 and 2013,respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions andother factors affecting the price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs as ofeach year-end.There are numerous uncertainties inherent in estimating reserves and related information, and different reservoir engineers often arrive at different estimatesfor the same properties. There can be no assurance that our estimated net proved reserves will be produced within the periods indicated or that prices andcosts will remain constant. As of February 8, 2016, the spot crude oil price was $29.71 per barrel, a 20% decrease since December 31, 2015 and a 39%decrease as compared to an average WTI of $48.75 per barrel during the year ended December 31, 2015. A further extended period of low prices for oil couldresult in a significant decrease in our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure in the future. Please see“Reserves sensitivity” below.Proved undeveloped reservesAt December 31, 2015, we had approximately 70.7 MMBoe of proved undeveloped reserves as compared to 125.7 MMBoe at December 31, 2014.The following table summarizes the changes in our proved undeveloped reserves during 2015 (in MBoe): At December 31, 2014125,743Extensions, discoveries and other additions26,278Purchases of minerals in place1,617Sales of minerals in place—Revisions of previous estimates(72,563)Conversion to proved developed reserves(10,419)At December 31, 201570,656During 2015, we spent a total of $242.4 million related to the development of proved undeveloped reserves, $105.7 million of which was spent on provedundeveloped reserves that represent wells in progress at year-end. The remaining $136.7 million resulted in the conversion of 10,419 MBoe of provedundeveloped reserves, or 8% of our proved undeveloped reserves balance at the beginning of 2015, to proved developed reserves. Our proved undevelopedreserves converted to proved developed reserves during 2015 amounted to 20% of our proved undeveloped reserves balance at the beginning of 2015 of125,743 MBoe less our net negative revisions of previous estimates during 2015 of 72,563 MBoe. We added 26,278 MBoe of proved undeveloped reservesin the Williston Basin as a result of our 2015 operated and non-operated drilling program and anticipated five-year drilling plan. We participated in121 gross (64.3 net) wells that were completed and brought on production during 2015. In addition, we purchased 1,617 MBoe of proved undevelopedreserves as a result of acquisitions during the year ended December 31, 2015. In 2015, our net negative revision of 72,563 MBoe, or 58% of our December 31,2014 proved undeveloped reserves balance, is primarily due to the removal of proved undeveloped reserves that are not economic at the lower oil price or areno longer aligned with our anticipated five-year drilling plan. This resulted in 259 gross (190.8 net) proved undeveloped locations with 71,945 MBoe ofreserves being removed from the December 31, 2015 estimated net proved8Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsreserves balance, most significantly, removing proved undeveloped reserves outside of our core acreage within the Williston Basin that were uneconomic asof December 31, 2015 due to the lower oil price.We expect to develop all of our proved undeveloped reserves as of December 31, 2015 within five years after the initial year booked. The future developmentof such proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as wellas access to liquidity sources, such as capital markets, our revolving credit facility and derivative contracts. All proved undeveloped locations are located onproperties where the leases are held by existing production or continuous drilling operations. Approximately 30% of our proved undeveloped reserves atDecember 31, 2015 are attributable to wells that have been drilled but not yet completed, and 100% of our undrilled reserves are within our core acreage inthe Williston Basin.Reserves sensitivityOur estimated net proved reserves at December 31, 2015 were prepared using SEC pricing for crude oil of $50.16 per barrel and natural gas of $2.63 perMMBtu. The current forward curve for commodity prices is significantly lower compared to year-end 2015 SEC pricing; therefore, the following sensitivitytable is provided to illustrate the estimated impact on our estimated proved reserves, PV-10 and Standardized Measure. In addition to different priceassumptions, the sensitivity case below includes assumed capital and expense reductions we expect to realize at lower commodity prices. The reduction inproved developed reserves is attributable to reaching the economic limit sooner. The reduction in proved undeveloped reserves is a result of well locationsno longer meeting our investment criteria as well as reaching the economic limit sooner.This sensitivity case is only to demonstrate the impact that a lower price and cost environment may have on estimated proved reserves, PV-10 andStandardized Measure. There is no assurance that these prices or assumed cost savings will actually be achieved. Actual at December 31, 2015 Sensitivity CaseOil price (per Bbl)(1)$50.16 $35.00Natural gas price (per MMBtu)(1)2.63 2.00 Capital expenditure reductionn/a 15%Operating expense reductionn/a 16% Estimated proved developed reserves (MMBoe)147.6 138.9Estimated proved undeveloped reserves (MMBoe)70.7 55.2Total estimated proved reserves (MMBoe)218.2 194.2 PV-10 (in millions)$2,022.7 $1,164.0Present value of future income taxes discounted at 10% (in millions)108.4 —Standardized Measure of discounted future net cash flows (in millions)$1,914.3 $1,164.0__________________ (1)Our estimated net proved reserves, PV-10 and Standardized Measure were determined using prices for oil and natural gas, without giving effect toderivative transactions, which were held constant throughout the life of the properties. The actual reserve estimates at December 31, 2015 wereprepared using SEC pricing, calculated as the unweighted arithmetic average first-day-of-the-month prices for the prior twelve months, which was$50.16/Bbl for oil and $2.63/MMBtu for natural gas for the year ended December 31, 2015. The sensitivity case prices represent potential SECpricing based on different pricing assumptions, which are in line with our budget and recent forward commodity prices for 2016. In both the actualand the sensitivity case, the prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductionsand other factors affecting the price received at the wellhead.Independent petroleum engineersOur estimated net proved reserves and related future net revenues and PV-10 at December 31, 2015, 2014 and 2013 are based on reports prepared byDeGolyer and MacNaughton, our independent reserve engineers, by the use of appropriate geologic, petroleum engineering and evaluation principles andtechniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of PetroleumEngineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007) anddefinitions and9Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentscurrent guidelines established by the SEC. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Calgary, Moscow andAlgiers. The firm’s more than 100 professionals include engineers, geologists, geophysicists, petrophysicists and economists engaged in the appraisal of oiland gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to thedomestic and international energy industry. DeGolyer and MacNaughton has provided such services for over 75 years. The Senior Vice President at DeGolyerand MacNaughton primarily responsible for overseeing the preparation of the reserve estimates is a Registered Professional Engineer in the State of Texaswith over 30 years of experience in oil and gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in PetroleumEngineering from The University of Texas at Austin in 1984, and he is a member of the International Society of Petroleum Engineers and the Society ofPetroleum Evaluation Engineers. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nordoes 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, andits employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.Technology used to establish proved reservesIn accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are thosequantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economicallyproducible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. Theterm “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, andprobabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. Reasonable certainty can beestablished using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by usingreliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and hasbeen demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are inaccordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitledStandards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007). The method or combinationof methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basicdata, and production history.Based on the current stage of field development, production performance, the development plans provided by us to DeGolyer and MacNaughton and theanalyses of areas offsetting existing wells with test or production data, reserves were classified as proved.For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserveswere estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production decline curves, reserveswere estimated only to the limits of economic production.Undeveloped reserves were estimated for locations adjacent to existing wells and are based on consideration of lateral length, completion and productionprofiles compared by appropriate target reservoir. In certain cases, when the previously named methods could not be used, reserves were estimated by analogywith similar wells or reservoirs for which more complete data was available.Internal controls over reserves estimation processWe employ DeGolyer and MacNaughton as the independent reserves evaluator for 100% of our reserves base. We maintain an internal staff of petroleumengineers and geoscience professionals who work closely with the independent reserve engineers to ensure the integrity, accuracy and timeliness of datafurnished for the reserves estimation process. Brett Newton, Senior Vice President of Asset Management and Chief Engineer, is the technical person primarilyresponsible for overseeing our reserves evaluation process. He has over 25 years of industry experience with positions of increasing responsibility inengineering and management. He holds both a Bachelor of Science degree and Master of Science degree in petroleum engineering. Mr. Newton reportsdirectly to our President and Chief Operating Officer.Throughout each fiscal year, our technical team meets with the independent reserve engineers to review properties and discuss evaluation methods andassumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reservesestimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to thefollowing:10Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents•Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs inputin our reserves database;•Review of working interests and net revenue interests in our reserves database against our well ownership system;•Review of historical realized prices and differentials from index prices 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 and ChiefEngineer;•Review of a preliminary copy of the reserve report by our President and Chief Operating Officer with our internal technical staff; and•Review of our reserves estimation process by our Audit Committee on an annual basis.Production, revenues and price historyWe produce and market oil and natural gas, which are commodities. The price that we receive for the oil and natural gas we produce is largely a function ofmarket supply and demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropicalstorms. Over or under supply of oil or natural gas can result in substantial price volatility. Oil supply in the United States has grown dramatically over thepast few years, and this has contributed to the current global oversupply of crude oil, which has caused a sharp decline in oil prices since mid-2014. In 2015,oil inventories continued to build as global oil supply continued to outpace demand. As of February 8, 2016, the spot crude oil price was $29.71 per barrel, a20% decrease since December 31, 2015 and a 39% decrease as compared to an average WTI of $48.75 per barrel during the year ended December 31, 2015.Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. Further declines in oil and natural gas prices,extended low oil and 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. Please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—Further declines, or extended current low commodity prices, 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 obligationsand financial commitments.”The following table sets forth information regarding our oil and natural gas production, realized prices and production costs for the periods indicated. Foradditional information on price calculations, please see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition andResults of Operations.” Year Ended December 31, 2015 2014 2013Net production volumes: Oil (MBbls)16,091 14,883 11,133Natural gas (MMcf)14,002 10,691 7,450Oil equivalents (MBoe)18,424 16,664 12,375Average daily production (Boe per day)50,477 45,656 33,904Average sales prices: Oil, without derivative settlements (per Bbl)(1)$43.04 $82.73 $92.34Oil, with derivative settlements (per Bbl)(1)(2)66.06 83.19 91.61Natural gas (per Mcf)(3)2.08 6.81 6.78Costs and expenses (per Boe of production): Lease operating expenses(4)$7.84 $10.18 $7.65Marketing, transportation and gathering expenses1.72 1.75 2.09Production taxes3.78 7.66 8.12Depreciation, depletion and amortization26.34 24.74 24.81General and administrative expenses5.02 5.54 6.09__________________ 11Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents(1)For the year ended December 31, 2013, average sales prices for oil is calculated using total oil revenues, excluding bulk oil sales of $5.8 million,divided by oil production.(2)Realized prices include gains or losses on cash settlements for our commodity derivatives, which do not qualify for and were not designated ashedging instruments for accounting purposes. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periodspresented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.(3)Natural gas prices include the value for natural gas and natural gas liquids.(4)For the year ended December 31, 2013, lease operating expenses include midstream income and operating expenses, which are included in wellservices and midstream revenues and well services and midstream operating expenses, respectively, for the years ended December 31, 2015 and 2014.Net production volumes for the year ended December 31, 2015 were 18,424 MBoe, an 11% increase from net production of 16,664 MBoe for the year endedDecember 31, 2014. Our net production volumes increased 1,760 MBoe over 2014 primarily due to a successful operated and non-operated drilling andcompletion program. Average oil sales prices, without derivative settlements, decreased by $39.69 per barrel, or 48%, to an average of $43.04 per barrel forthe year ended December 31, 2015 as compared to the year ended December 31, 2014. Giving effect to our derivative transactions in both periods, our oilsales prices decreased $17.13 per barrel to $66.06 per barrel for the year ended December 31, 2015 from $83.19 per barrel for the year ended December 31,2014.Net production volumes for the year ended December 31, 2014 were 16,664 MBoe, a 35% increase from net production of 12,375 MBoe for the year endedDecember 31, 2013. Our net production volumes increased 4,289 MBoe over 2013 due to a successful operated and non-operated drilling and completionprogram. Average oil sales prices, without derivative settlements, decreased by $9.61 per barrel, or 10%, to an average of $82.73 per barrel for the year endedDecember 31, 2014 as compared to the year ended December 31, 2013. Giving effect to our derivative transactions in both periods, our oil sales pricesdecreased $8.42 per barrel to $83.19 per barrel for the year ended December 31, 2014 from $91.61 per barrel for the year ended December 31, 2013.Productive wellsThe following table presents the total and operated gross and net productive wells as of December 31, 2015: Total wells Operated wells Gross Net Gross NetBakken and Three Forks1,095 595.5 731 569.5Other155 93.7 101 89.3Total wells1,250 689.2 832 658.8All 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 arethe total of our working interests owned in gross wells.AcreageThe following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31,2015. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. Gross NetDeveloped acres505,706 377,834Undeveloped acres161,231 106,911Total acres666,937 484,745We increased our acreage that is held by production to 442,292 net acres at December 31, 2015 from 433,794 net acres at December 31, 2014.Undeveloped acreageThe following table sets forth the number of gross and net undeveloped acres as of December 31, 2015 that will expire over the next three years unlessproduction is established within the spacing units covering the acreage prior to the expiration dates:12Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents Undeveloped acres expiring Gross NetYear ending December 31, 201630,569 16,55620179,729 8,93520188,378 7,938Drilling and completion activityThe following table summarizes our completion activity for the years ended December 31, 2015, 2014 and 2013. Gross wells reflect the sum of all productiveand dry wells, operated and non-operated, in which we own a working interest. Net wells reflect the sum of our working interests in gross wells. The gross andnet wells represent wells completed during the periods presented, regardless of when drilling was initiated. Year ended December 31, 2015 2014 2013 Gross Net Gross Net Gross NetDevelopment wells: Oil115 59.1 188 102.6 188 75.3Gas— — — — — —Dry— — — — — —Total development wells115 59.1 188 102.6 188 75.3Exploratory wells: Oil6 5.2 81 48.5 62 39.8Gas— — — — — —Dry— — — — — —Total exploratory wells6 5.2 81 48.5 62 39.8Total wells121 64.3 269 151.1 250 115.1In 2013, we focused on delineation and appraisal of the Bakken and Three Forks formations, resulting in substantially all of our acreage being delineated asof December 31, 2013. In 2014, we focused on full field development. In 2015, we continued in full field development mode with a focus on improvingcapital efficiency and completing more wells using high-intensity completion techniques. We also continued to participate in a number of wells on a non-operated basis.We did not drill any dry hole wells in 2015, 2014 or 2013.As of December 31, 2015, we had three operated rigs running, 2 gross (0.4 net) operated wells drilling, as one rig was in the process of moving to the nextwell, and an inventory of 85 gross operated wells waiting on completion. We expect to continue to focus on drilling with two operated rigs in the Bakken andThree Forks formations within our core acreage in 2016.Capital expenditure budgetIn 2015, we spent $610.0 million on capital expenditures, which represented a 61% decrease from the $1,572.6 million spent during 2014. This decrease wasdue to reduced drilling and completion activity as a result of lower commodity prices in 2015 coupled with lower well costs as a result of both improvedoperational efficiency and lower service costs, partially offset by higher capital expenditures for OMS, primarily related to the natural gas processing plant weare constructing in the Wild Basin area of our core acreage in North Dakota. See “Item 7. Management’s Discussion and Analysis of Financial Condition andResults of Operations—Liquidity and capital resources—Cash flows used in investing activities.”We have decreased our planned 2016 capital expenditures as compared to 2015 as a result of the current lower commodity prices. Our total 2016 capitalexpenditure budget is $400 million, which includes $237 million for exploration and production (“E&P”) capital expenditures and $163 million for non-E&P capital expenditures, including OMS, OWS, capitalized interest and administrative capital. We plan to complete approximately 46 gross (28.6 net)operated wells and participate in 0.6 net non-operated wells that are expected to be completed and brought on production in 2016. Our planned E&P capitalexpenditures include $200 million of drilling and completion (including production-related equipment) capital expenditures for operated and13Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsnon-operated wells (including expected savings from services provided by OWS and OMS) and $37 million of other E&P capital expenditures. Our plannednon-E&P capital expenditures include $140 million of midstream capital to continue to develop the natural gas processing plant and other infrastructure inWild Basin and $23 million of other non-E&P capital expenditures.While we have budgeted $400 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on marketconditions, our ability to secure external funding for our Wild Basin project and the success of our drilling results as the year progresses. Additionally, if weacquire additional acreage, our capital expenditures may be higher than budgeted. See “Item 7. Management’s Discussion and Analysis of FinancialCondition and Results of Operations—Liquidity and capital resources.”Description of propertiesOur 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 theWilliston Basin that target several different zones, our development activities are currently concentrated in the Bakken and Three Forks formations. Ourmanagement team originally targeted the Williston Basin because of its oil-prone nature, multiple producing horizons, substantial resource potential andmanagement’s previous professional history in the basin. The Williston Basin also generally has established infrastructure and access to materials andservices.The entire Williston Basin is spread across North Dakota, South Dakota, Montana and parts of southern Canada. The basin produces oil and natural gas fromnumerous producing horizons including, but not limited to, the Bakken, Three Forks, Madison and Red River formations. A report issued by the UnitedStates Geological Survey in April 2008 classified these formations as the largest continuous oil accumulation ever assessed by it in the contiguous UnitedStates. The Williston Basin has recently been one of the most actively drilled unconventional oil resource plays in the United States, reaching over 200 rigsdrilling in the basin in 2014, although the active rig count decreased throughout 2015 due to low oil prices and fell to fewer than 50 rigs drilling in the basinin early 2016. Most rigs that are running in the Williston Basin are focused on drilling areas with the highest estimated ultimate recoveries that haveattractive economics even in depressed oil price environments. Our development activity is focused in the deepest part of the Williston Basin, which we callthe core.The Devonian-age Bakken formation is found within the Williston Basin underlying portions of North Dakota and Montana and is comprised of threelithologic members including the upper shale, middle Bakken and lower shale. The formation ranges up to 150 feet thick. The upper and lower shales arehighly organic, thermally mature and over pressured and can act as both a source and reservoir for the oil. The middle Bakken, which varies in compositionfrom a silty dolomite to shaley limestone or sand, also serves as a reservoir and is a critical component for commercial production. Generally, the Bakkenformation is found at vertical depths of 8,500 to 11,500 feet. Based on our geologic interpretation of the Bakken formation, the evolution of completiontechniques, our own drilling results and publicly available drilling results for other operators in the basin, we believe that a substantial portion of ourWilliston 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. The Three Forksformation 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 ofcompletion techniques, our own drilling results and publicly available drilling results for other operators in the basin, we believe that much of our WillistonBasin acreage is prospective in the Three Forks formation.Our total leasehold position in the Williston Basin as of December 31, 2015 consisted of 484,745 net acres. Our estimated net proved reserves in theWilliston Basin were 218.2 MMBoe at December 31, 2015. Of our estimated net proved reserves in the Williston Basin, approximately 147.6 MMBoe wereproved developed reserves, which are comprised of a combination of wells drilled to conventional reservoirs, Bakken and Three Forks wells drilled with oldercompletion techniques, and to a much larger extent, Bakken and Three Forks wells drilled with completion techniques similar to those we currently employ.Of our estimated net proved reserves, 70.7 MMBoe were proved undeveloped reserves, all of which consisted of Bakken and Three Forks wells to be drilledwith more recent completion techniques, although our proved undeveloped reserves do not incorporate the impact of high intensity completion techniques.As of December 31, 2015, we had a total of 689.2 net operated and non-operated producing wells and 658.8 net operated producing wells in the WillistonBasin. We had average daily production of 50,477 net Boe per day for the year ended December 31, 2015 in the Williston Basin. During 2015, our Bakkenand Three Forks wells produced a daily average of 49,788 net Boe per day with 595.5 net producing wells on December 31, 2015. Accordingly, our 595.5 netBakken and Three Forks wells were responsible for 99% of our average daily production during 2015. As of December 31, 2015, our working interest for allproducing wells averaged 56% and in the wells we operate was approximately 79%. As of December 31, 2015, we had 117 gross (63.8 net) wells in theprocess of being drilled or completed in the Williston Basin, which includes 2 gross operated wells drilling, 85 gross operated wells waiting on completionand 3014Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsgross non-operated wells drilling or completing. We participated in 121 gross (64.3 net) wells that were completed and brought on production during 2015.Marketing, transportation and major customersThe Williston Basin crude oil rail and pipeline transportation and refining infrastructure has grown substantially in recent years, largely in response todrilling activity in the Bakken and Three Forks formations. In December 2015, oil production in North Dakota was approximately 1,152,000 barrels perday. According to the North Dakota Pipeline Authority website’s data last updated January 15, 2016, there was approximately 827,000 barrels per day ofcrude oil pipeline transportation capacity and approximately 1,490,000 barrels per day of specifically dedicated rail loading capacity in the Williston Basinas of December 31, 2015. In 2015, we continued to sell a significant amount of our crude oil production through gathering systems connected to multiplepipeline and rail facilities. These gathering systems, which typically originate at the wellhead, reduce the need to transport barrels by truck from thewellhead. As of December 31, 2015, we were flowing over 80% of our gross operated oil production through these gathering systems.Crude oil produced and sold in the Williston Basin has historically sold at a discount to WTI due to transportation costs and takeaway capacity. In the past,there have been periods when this discount has substantially increased due to the production of oil in the area increasing to a point that it temporarilysurpasses the available pipeline transportation, rail transportation and refining capacity in the area. Expansions of both rail and pipeline facilities havereduced the prior constraint on oil transportation out of the Williston Basin and improved netback pricing received at the lease. In 2015, our pricedifferentials relative to WTI strengthened as new pipelines opened to eastern Canada and U.S. markets and transportation on rail gradually declined. In thefirst quarter of 2015, as WTI declined, our price differentials increased as a percentage of WTI to a 16% discount but decreased in terms of the dollar per barreldiscount to WTI to an average of $7.85 per barrel of oil. In the second quarter of 2015, as WTI improved, our price differentials decreased to approximately10% as a percentage of WTI and continued to decrease in terms of the dollar per barrel discount to WTI to an average of $5.90 per barrel of oil. In the secondhalf of 2015, while WTI fell again, our price differentials strengthened, decreasing to less than $5.00 per barrel of oil and remaining at approximately 10% asa percentage of WTI. Our market optionality on the crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order tooptimize price realizations. For a discussion of the potential risks to our business that could result from transportation and refining infrastructure constraintsin the Williston Basin, please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—Insufficient transportation orrefining 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. Ourmarketing 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 someof these factors, please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—Market conditions or operationalimpediments may hinder our access to oil and natural gas markets or delay our production” and “Risk Factors—Risks related to the oil and natural gasindustry and our business—Insufficient transportation or refining capacity in the Williston Basin could cause significant fluctuations in our realized oil andnatural gas prices.” At the end of 2015, the U.S. government lifted the long-standing ban on crude oil exports. While we believe this could have a positiveimpact on the long-term value of Bakken crude oil, current market conditions are not expected to result in sizeable quantities of U.S. crude oil being exportedout of the country.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 usto market and sell our oil and natural gas to a broader array of potential purchasers. As of December 31, 2015, we sold a substantial majority of our oil andcondensate through bulk sales at delivery points on crude oil gathering systems or directly at the wellhead to a variety of purchasers at prevailing marketprices under short-term contracts that normally provide for us to receive a market-based price, which incorporates regional differentials that include, but arenot limited to, transportation costs and adjustments for product quality. We also entered into various short-term sales contracts for a portion of our portfolio atfixed differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customerwould have a material adverse effect on our results of operations or cash flows.For the year ended December 31, 2015, sales to Shell Trading (US) Company accounted for approximately 10% of our total sales. For the years endedDecember 31, 2014 and 2013, sales to Musket Corporation accounted for approximately 13% and 11% of our total sales, respectively. No other purchasersaccounted for more than 10% of our total oil and natural gas sales for the years ended December 31, 2015, 2014 and 2013. We believe that the loss of any ofthese 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 theWilliston Basin.15Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSince most of our oil and natural gas production is sold under market-based or spot market contracts, the revenues generated by our operations are highlydependent 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 factorsbeyond our control, including but not limited to seasonality, weather, competition, availability of transportation and gathering capabilities, worldwide andregional economic conditions, global and domestic oil supply, foreign imports, political conditions in other oil-producing and natural gas-producingregions, 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—Further declines, or extended current low commodity prices, inoil 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 capitalexpenditure obligations and financial commitments.” Furthermore, a decrease in the price of oil and natural gas could have an adverse effect on the carryingvalue of our estimated proved reserves and on our revenues, profitability and cash flows. Please see “Item 1A. Risk Factors—Risks related to the oil andnatural gas industry and our business—If oil and natural gas prices remain at their current level for an extended period of time or continue to decline, we maybe 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 ouraccess to oil and natural gas markets or delay our production.”CompetitionThe oil and natural gas industry is worldwide and highly competitive in all phases. We encounter competition from other oil and natural gas companies in allareas of operation, including the acquisition of leasing options on oil and natural gas properties to the exploration and development of those properties. Ourcompetitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals and drilling andincome programs. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resourcesthan 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, bidfor and purchase a greater number of properties and locations than our financial or human resources permit. Our ability to acquire additional properties and todiscover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitiveenvironment. Please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—Competition in the oil and natural gasindustry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.”Title to propertiesAs 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 tosignificant title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing anytitle defects at our expense. We generally will not commence drilling operations on a 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 inaccordance with general industry standards. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the mostsignificant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil andnatural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our revolving credit facility, liens for current taxesand 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.”SeasonalityWinter weather conditions and lease stipulations can limit or temporarily halt our drilling, completion and producing activities and other oil and natural gasoperations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operatingand 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 industry16Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOur operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operationsare, 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 foroil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related topermits 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 useand restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and the abandonment ofwells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units orproration 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 thatgenerally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production fromfields 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 doingbusiness and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, and that continuedsubstantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, suchlaws and regulations are frequently amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliancewith environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposalsand 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 oilSales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenactprice 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 torate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oilpipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certaincircumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates foroil 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 FERCreviews the appropriateness of the index level in relation to changes in industry costs. Most recently, on December 16, 2010, the FERC established a newprice 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 thedegree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates areequally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is ofmaterial 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, commoncarriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at fullcapacity, access is generally governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oilpipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.We sell a significant amount of our crude oil production through gathering systems connected to rail facilities. Several derailments of freight trains, includingthe events in July 2013 in Lac Mégantic, have led federal and state regulators to examine whether the hazardous nature of crude oil from the Bakken shale isbeing assessed properly prior to its shipment. In particular, there are concerns that the testing and ensuing designations of the crude oil on the shippingdocumentation do not in all cases accurately capture the flammability of the Bakken crude oil. On January 2, 2014, the Pipeline and Hazardous MaterialsSafety Administration (“PHMSA”) released a Safety Alert alerting regulators, emergency responders, transporters and shippers that crude oil from the BakkenShale may have flammability characteristics that are different from other forms of crude oil and that it was vital that all shipments of crude oil be tested andproperly characterized on all shipping documentation. The Safety Alert also notified the regulated community that PHMSA and the Federal RailroadAdministration have launched “Operation Classification,” which is an ongoing enforcement initiative that involves unannounced inspections on crude oilshipments to test the contents of the shipments in order to ensure that they are properly characterized. In August 2014, the U.S. Department of Transportationreleased a report finding that, based on the results of Operation Classification from August 201317Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsto May 2014, Bakken crude oil tends to be more volatile and flammable than other crude oils, and thus poses an increased risk for a significant accident.In addition, these events have also spurred efforts to improve the safety of tank cars that are used in transporting crude oil by rail. Since 2011, all new railroadtank cars that have been built to transport crude oil or other petroleum type fluids (e.g., ethanol) have been built to more stringent safety standards. In May2015, PHMSA adopted a final rule that, among other things, imposes a new and enhanced tank car design standard for certain tank cars carrying crude oil andethanol, a phase out by as early as January 2018 for older DOT-111 tank cars that are not retrofitted, and a classification and testing program for unrefinedpetroleum based products, including crude oil. The rule also includes new operational requirements such as routing analyses, speed restrictions and enhancedbraking controls. Safety improvements or updates to existing tank cars that are imposed under the May 2015 PHMSA final rule could drive up the cost oftransport and lead to shortages in availability of tank cars. We do not currently own or operate rail transportation facilities or rail cars; however, we cannotassure that costs incurred by the railroad industry to comply with these enhanced standards resulting from PHMSA’s final rule will not increase our costs ofdoing business or limit our ability to transport and sell our crude oil at favorable prices, the consequences of which could be material to our business,financial condition or results of operations. However, we believe that any such consequences would not affect our operations in any way that is of materialdifference from those of our competitors who are similarly situated.Efforts are likewise underway in Canada to assess and address risks from the transport of crude oil by rail. Shortly after the Lac Mégantic tragedy, TransportCanada issued a series of emergency directives aimed at certain practices that were identified immediately after the accident. Likewise, Transport Canada isassessing the compensation and liability scheme for shipments by rail so that sufficient funds are available to compensate victims and respond to the incidentwithout making taxpayers fund any aspect of those efforts. Transport Canada has also issued recent legal requirements that align with the U.S. May 2015PHMSA final rule in many respects. In January 2014, the Canadian Transportation Safety Board made several recommendations to Transport Canadaregarding tank car safety, routing of freight trains and the capabilities of emergency responders. In April 2014, Transport Canada issued a protective orderprohibiting oil shippers from using 5,000 of the DOT-111 tank cars and imposing a phase out for tank cars that do not meet certain safety requirements by asearly as May 2017. Transport Canada also imposed a 50 mile-per-hour speed limit on trains carrying hazardous materials and required all crude oil shipmentsin Canada to have an emergency response plan.We believe we are in substantial compliance with applicable hazardous materials transportation requirements related to our operations. We do not believethat compliance with federal, state or local hazardous materials transportation regulations will have a material adverse effect on our financial position orresults of operations. However, future events, such as changes in existing laws (including changes in the interpretation of existing laws), the promulgation ofnew laws and regulations, including any voluntary measures introduced by the rail industry, that result in new requirements for the design, construction oroperation of tank cars used to transport crude oil, or the development or discovery of new facts or conditions could increase our costs of doing business andlimit our ability to transport and sell our crude oil at favorable prices, the consequences of which could be material to our business, financial condition orresults of operations. However, we believe that any such consequences would not affect our operations in any way that is of material difference from those ofour competitors who are similarly situated.Regulation of transportation and sales of natural gasHistorically, 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 theprices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact pricecontrols in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural GasWellhead 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, aswell as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible tonatural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve thecompetitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more directcontractual 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 interstatepipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure underwhich 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 notdirectly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.18Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIn 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in naturalgas 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-yearexperimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal andinformation reporting. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the lessstringent regulatory approach recently established by the FERC under Order No. 637 will continue. However, we do not believe that any action taken willaffect 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, withregard to our physical sales of energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERCand/or the Commodity Futures Trading Commission (“CFTC”) and the Federal Trade Commission (“FTC”). Please see below the discussion of “Other federallaws and regulations affecting our industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we couldalso 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 certainnatural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificatestatus, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume ofnatural 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 theFERC 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 generallyincludes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally beenaffirmatively 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 byintrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight andscrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generallyaffect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gastransportation 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 materialdifference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects themarketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.Regulation of productionThe 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, stateand local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own and operate properties inNorth Dakota and Montana, which have regulations governing conservation matters, including provisions for the unitization or pooling of oil and naturalgas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging andabandonment 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 numberof 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,both states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions.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 thesame regulatory requirements and restrictions that affect our operations.Other federal laws and regulations affecting our industryEnergy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (“EPAct 2005”). EPAct 2005 is acomprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy thataffects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes itunlawful 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 the19Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsFERC 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 underthe 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 saleof natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision ofEPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale ofnatural 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 anydevice, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statementsmade 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-manipulationrules 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 andstorage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities areconducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirementsunder Order No. 704, as described below. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcementauthority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penaltiesand fines.FERC market transparency rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amendedby 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 naturalgas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketersand 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 calendaryear 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 todetermine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants toindicate 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 thepetroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleumdistillates 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 astatement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation ofthis 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 CommissionAct.North Dakota Industrial Commission oil and gas rule changes. The North Dakota Industrial Commission (“NDIC”) has adopted more stringent rule changesto its existing oil and gas regulations. The rules became effective on April 1, 2012 and, among other things, impose relatively higher bonding amounts for thedrilling of wells, severely restrict the discharge and storage of production wastes such as produced water, drilling mud, waste oil and other wastes in earthenpits, 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 productionoperators in general and us in particular increased our well costs from 2012 to 2015, and we expect to continue to incur these increased costs in order toremain in compliance.In 2014, the NDIC adopted an order intended to reduce natural gas flaring, which order was subsequently modified in late 2015. Please see below thediscussion of “Environmental protection and natural gas flaring initiatives.” In addition, on December 9, 2014, the NDIC adopted new conditioningstandards to improve the safety of Bakken crude oil for transport. The rule became effective April 1, 2015 and sets operating standards for conditioningequipment to properly separate production fluids. The rule includes parameters for temperatures and pressures for production equipment. The rule alsoaddresses limits to vapor pressure of produced crude oil.Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict theultimate 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 actionmaterially differently than similarly situated competitors.Environmental and occupational health and safety regulationOur exploration, development and production operations are subject to stringent federal, regional, state and local laws and regulations governingoccupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulationsmay, among other things, require the acquisition of permits to conduct20Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsexploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment; limit or prohibitconstruction or drilling activities in environmentally-sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered species; requireinvestigatory and remedial actions to mitigate pollution conditions; impose obligations to reclaim and abandon well sites and pits; and impose specificcriteria addressing worker protection. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative,civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the occurrence of delays in the development ofprojects 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 andnatural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing businessin 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 infederal or state environmental laws and regulations or reinterpretation of applicable enforcement policies that result in more stringent and costly wellconstruction, drilling, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirements could have amaterial 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 aresult of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are insubstantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a materialadverse 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 suchexisting 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 and occupational health and safety laws, as amended from time to time, to whichour business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations orfinancial position.Hazardous substances and wastesThe Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state lawsimpose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for therelease of a “hazardous substance” into the environment. These classes of persons include current and prior owners or operators of the site where the releaseoccurred and entities that disposed or arranged for the disposal of the hazardous substances released 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, fordamages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, insome 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 personsthe costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedlycaused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may beregulated as hazardous substances.We are also subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. RCRA imposes strictrequirements on the generation, storage, treatment, transportation, disposal and cleanup of hazardous and nonhazardous wastes. Under the authority of theEPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. RCRA currentlyexempts certain drilling fluids, produced waters and other wastes associated with exploration, development and production of oil and natural gas fromregulation as hazardous wastes. These wastes, instead, are regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federallaws. However, it is possible that certain oil and natural gas exploration, development and production wastes now classified as nonhazardous wastes could beclassified as hazardous wastes in the future. For example, in August 2015, several non-governmental organizations filed notice of intent to sue the EPA underRCRA for, among other things, the agency’s alleged failure to reconsider whether such exclusion should continue to apply. Repeal or modification of thisRCRA exclusion or similar exemptions under state law could increase the amount of hazardous waste we are required to manage and dispose of and couldcause 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 the course ofour 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 naturalgas. Although we have utilized operating and disposal practices that were standard in the industry at21Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsthe 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 theseproperties have been operated by the third parties whose treatment and disposal or release of petroleum hydrocarbons, hazardous substances and wastes werenot under our control. These properties and the substances disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Underthese laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), toclean up contaminated property (including contaminated groundwater) and to perform remedial plugging or pit closure operations to prevent futurecontamination.Air emissionsThe federal Clean Air Act (“CAA”) and comparable state laws and regulations restrict the emission of various air pollutants from many sources through airemissions standards, construction and operating permitting programs, and the imposition of other monitoring and reporting requirements. These laws andregulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantlyincrease air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions ofcertain pollutants. Obtaining permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may berequired to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in October 2015, the EPAissued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion under boththe primary and secondary standards to provide requisite protection of public health and welfare, respectively. We review new rules such as this one to assesstheir impact on our operations. Compliance with this final rule or any other new legal requirements could, among other things, require installation of newemission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs,which could adversely impact our business.Environmental protection and natural gas flaring initiativesWe attempt to conduct our operations in a manner that protects the health, safety and welfare of the public, our employees and the environment. We arefocused on the reduction of air emissions produced from our operations, particularly with respect to flaring of natural gas from our operated well sites. Therapid growth of crude oil production in North Dakota in recent years, coupled with a historical lack of natural gas gathering infrastructure in the state, has ledto efforts to reduce flaring of natural gas produced in association with crude oil production. We recognize the environmental and financial risks associatedwith natural gas flaring, and we seek to manage these risks on an ongoing basis and reduce flaring from our operated well sites.We believe that one of the leading causes of natural gas flaring from the Bakken and Three Forks formations is the inability of operators to promptly connecttheir wells to natural gas processing and gathering infrastructure due to external factors out of the control of the operator, such as, for example, the granting ofright-of-way access by land owners, investment from third parties in the development of gas gathering systems and processing facilities, and the developmentand adoption of regulations. However, we have allocated significant resources to connect our Bakken and Three Forks wells to natural gas infrastructure in atimely manner to reduce our flared volumes. We have exceeded a goal that we voluntarily set in 2014 to maintain well connections for an average of 90% ofour operated Bakken and Three Forks wells, by having approximately 98% and 97% of our operated Bakken and Three Forks wells connected to gatheringsystems as of December 31, 2015 and 2014, respectively. We believe that achieving this goal helps us to minimize our flared volumes of natural gas.On July 1, 2014, the NDIC adopted Order No. 24665 (the “July 2014 Order”), pursuant to which the agency adopted legally enforceable “gas capturepercentage goals” targeting the capture of 74% of natural gas produced in the state by October 1, 2014, 77% of such gas by January 1, 2015, 85% of such gasby January 1, 2016 and 90% of such gas by October 1, 2020. Modification of the July 2014 Order was announced by the NDIC in the fourth quarter of 2015,resulting in the existing January 1, 2015 gas capture rate of 77% being extended to April 1, 2016 and updated gas capture rates of 80% by April 1, 2016, 85%by November 1, 2016, 88% by November 1, 2018 and 91% by November 1, 2020. The July 2014 Order established an enforcement mechanism for policyrecommendations that were previously adopted by the NDIC in March 2014. Those recommendations required all exploration and production operatorsapplying for new drilling permits in the state after June 1, 2014 to develop Gas Capture Plans that provide measures for reducing the amount of natural gasflared by those operators so as to be consistent with the agency’s gas capture percentage goals. In particular, the July 2014 Order provided that after an initial90-day period, wells must meet or exceed the NDIC’s gas capture percentage goals on a per-well, per-field, county or statewide basis. Failure to comply withthe gas capture percentage goals will result in an operator having to restrict its production to 200 barrels of oil per day if at least 60% of the monthly volumeof associated natural gas produced from the well is captured, or 100 barrels of oil per day if less than 60% of such monthly volume of natural gas is captured.As of December 31, 2015, we were capturing approximately 91% of our natural gas production in North Dakota. While we were in compliance with these22Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsrequirements as of December 31, 2015 and expect to remain in compliance in the future, there is no assurance that we will be able to remain in compliance inthe future or that such future compliance will not have a material adverse effect on our business and operation results.Climate changeThe EPA has determined that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and theenvironment because emissions of such gases are contributing to warming of the Earth’s atmosphere and other climatic changes. In response to thisdetermination, the EPA adopted regulations under existing provisions of the CAA that establish Prevention of Significant Deterioration (“PSD”) constructionand Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, orcriteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available controltechnology” standards, which typically will be established by the states. These EPA rules could adversely affect our operations and restrict or delay ourability to obtain air permits for new or modified facilities. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions fromspecified sources in the United States on an annual basis, including, among others, oil and natural gas production facilities, which include certain of ouroperations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoringactivities are in substantial compliance with applicable reporting obligations.While from time to time Congress has considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adoptedlegislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regionalefforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources ofGHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in thecoming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand forrefined products. The adoption of any new legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from ourequipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand forthe oil and natural gas we produce. For example, in August 2015, the EPA announced proposed rules, expected to be finalized in 2016, that would establishnew controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category,including production activities, as part of an overall effort to reduce methane emissions by up to 45% in 2025. On an international level, the United States isone of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their ownGHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. It is not possible at this time topredict how new methane restrictions would impact the our business or how or when the United States might impose restrictions on GHGs as a result of theinternational agreement agreed to in Paris.Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climatechanges that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were tooccur, they could have an adverse effect on our exploration and production operations.Water dischargesThe Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls regarding the discharge ofpollutants into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with theterms of a permit issued by the EPA or the analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminalpenalties for non-compliance with discharge permits or other requirements of 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 ofnavigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws requireindividual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibitsthe discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The EPA released a final rule in May 2015 thatattempted to clarify federal jurisdiction under the Clean Water Act over waters of the United States, but a number of legal challenges to this rule are pending,and implementation of the rule has been stayed nationwide. To the extent this rule expands the scope of the Clean Water Act’s jurisdiction, drilling programscould incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.The Oil Pollution Act of 1990 (“OPA”) amends the Clean Water Act, and sets minimum standards for prevention, containment and cleanup of oil spills. TheOPA applies to vessels, offshore facilities and onshore facilities, including exploration and23Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsproduction facilities that may affect waters of the United States. Under the OPA, responsible parties including owners and operators of onshore facilities maybe 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. TheOPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil intowaters of the United States.Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which maybe disposed of by means of injection into underground wells situated in non-producing subsurface formations. The NDIC rule changes effective in 2012severely restrict the discharge and storage of production wastes including produced water in earthen pits, which increases the likelihood that injection wellsare used to dispose of appropriate waste streams. These injection wells are regulated by the federal Safe Drinking Water Act and analogous state laws. Theunderground injection well program under the Safe Drinking Water Act requires permits from the EPA or analogous state agency for disposal wells that weoperate, establishes minimum standards for injection well operations and restricts the types and quantities of fluids that may be injected. Any leakage fromthe subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, imposition offines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources and imposition of liability by landowners orother parties claiming damages for alternative water supplies, property damages and personal injuries. Moreover, any changes in the laws or regulations or theinability 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 ouroperations, which costs could be significant. Furthermore, in response to recent seismic events near underground injection wells used for the disposal of oiland gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and somestates have shut down or imposed moratoria on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use ofunderground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and ourability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.Hydraulic fracturing activitiesHydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from unconventional formations, includingshales. The process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rockand stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typicallyregulated by state oil and natural gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. Forexample, the EPA issued CAA final regulations in 2012 and proposed additional CAA regulations in August 2015 governing performance standards for theoil and natural gas industry; proposed in April 2015 effluent limitations guidelines that waste water from shale natural gas extraction operations must meetbefore discharging to a treatment plant; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic SubstancesControl Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the federal Bureau of Land Management (“BLM”)published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands but, inSeptember 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appealand is being separately appealed by certain environmental groups.From time to time Congress has considered legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and torequire disclosure of the chemicals used in the hydraulic fracturing process. In addition, 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. Statescould elect to prohibit hydraulic fracturing altogether, following the lead of the State of New York in 2015. Local government also may seek to adoptordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.Nevertheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where weoperate, 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 are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council onEnvironmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Also, the EPA released its draft report on the potentialimpacts of hydraulic fracturing on drinking water resources in June 2015, which report concluded that hydraulic fracturing activities have not led towidespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulicfracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA’s Science Advisory Board provided itscomments on the draft study, indicating its concern that the EPA’s conclusion of no widespread, systemic impacts24Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentson drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described inthe body of the draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report, whenissued, as well as any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulatehydraulic fracturing.Please see “Item 1A. Risk Factors—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.”Endangered Species Act considerationsThe federal Endangered Species Act (“ESA”) may restrict exploration, development and production activities that may affect endangered and threatenedspecies or their habitats. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the UnitedStates and prohibits the taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federalagencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed speciesor modify their critical habitats. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. Ifendangered or threatened species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities orabandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approvedby the U.S. District Court for the District of Columbia in 2011, the U.S. Fish and Wildlife Service is required to make a determination on a listing of numerousspecies as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The designation of previously unprotectedspecies as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from speciesprotection measures or could result in delays or limitations on our exploration and production activities that could have an adverse impact on our ability todevelop and produce reserves.Operations on federal landsPerformance of oil and gas exploration and production activities on federal lands, including Indian lands and lands administered by the federal BLM aresubject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs, toevaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment. In the course of suchevaluations, 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 available for public review and comment. Depending on anymitigation strategies recommended in such environmental assessments or environmental impact statements, we could incur added costs, which could besubstantial, and be subject to delays or limitations in the scope of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appealor litigation, any or all of which may delay or halt our exploration and production activities.Employee health and safetyWe are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparablestate 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 bemaintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and localgovernment authorities and citizens.EmployeesAs of December 31, 2015, we employed 535 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 ouremployees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services.OfficesAs of December 31, 2015, we leased 111,628 square feet of office space in Houston, Texas at 1001 Fannin Street, where our principal offices are located. Thelease for our Houston office expires in September 2020. We also own field offices in the North Dakota communities of Williston, Powers Lake and Alexander.Available information25Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsWe are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any documentsfiled 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 ofthe 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 documentretrieval 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 (“NYSE”) under the symbol “OAS.” Our reports, proxy statements and otherinformation 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 reasonablypracticable after we electronically file such material with the SEC. Information contained on our website is not incorporated by reference into this AnnualReport on Form 10-K.26Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsItem 1A. Risk FactorsOur 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, actuallyoccurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks notpresently 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 businessFurther declines, or extended current low commodity prices, in oil and, to a lesser extent, natural gas prices may adversely affect our business, financialcondition 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. Oiland natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.For example, average daily prices for WTI crude oil ranged from a high of $61.36 per barrel to a low of $34.55 per barrel during 2015. Average daily pricesfor NYMEX Henry Hub natural gas ranged from a high of $3.32 per MMBtu to a low of $1.63 per MMBtu during 2015. Historically, the markets for oil andnatural 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 ourproduction, 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 andconditions 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. Low oil and natural gasprices will reduce our cash flows, borrowing ability, the present value of our reserves and our ability to develop future reserves. See “Our exploration,development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactoryterms, which could lead to expiration of our leases or a decline in our estimated net oil and natural gas reserves” below. Low oil and natural gas prices mayalso 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 netrevenues 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”below.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 incredit 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 topursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptionsand volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to financeour operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability toachieve our planned operating results.27Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsWe 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 canmanage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligationsand other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affectour 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 beyondour 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 ourdebt, 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 ourborrowings or they could prevent us from making payments on our senior unsecured notes. If amounts outstanding under our revolving credit facility or oursenior 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 ourother debt holders. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and capitalresources.”Our revolving credit facility and the indentures governing our senior unsecured notes all contain operating and financial restrictions that may restrict ourbusiness and financing activities.Our revolving credit facility and the indentures governing our senior unsecured notes contain a number of restrictive covenants that impose significantoperating 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 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 are limited in the manner in which we conduct our business, and we may be unable to engage in favorable businessactivities or finance future operations or capital needs.Our ability to comply with some of the covenants and restrictions contained in our revolving credit facility and the indentures governing our seniorunsecured notes may be affected by events beyond our control. If market or other economic conditions deteriorate or if oil and natural gas prices remain attheir current level for an extended period of time or continue to decline, our ability to comply with these covenants may be impaired. A failure to complywith the covenants, ratios or tests in our revolving credit facility, the indentures governing our senior unsecured notes or any future indebtedness could resultin an event of default under our revolving credit facility, the indentures governing our senior unsecured notes or our future indebtedness, which, if not curedor waived, could have a material adverse effect on our business, financial condition and results of operations.28Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIf an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder:•would not be required to lend any additional amounts to us;•could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;•may have the ability to require us to apply all of our available cash to repay these borrowings; or•may prevent us from making debt service payments under our other agreements.A payment default or an acceleration under our revolving credit facility could result in an event of default and an acceleration under the indentures for oursenior unsecured notes. If the indebtedness under the notes were to be accelerated, there can be no assurance that we would have, or be able to obtain,sufficient funds to repay such indebtedness in full. In addition, our obligations under our revolving credit facility are collateralized by perfected first priorityliens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 90% of the reservevalue as determined by reserve reports, and if we are unable to repay our indebtedness under the revolving credit facility, the lenders could seek to forecloseon our assets. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and capitalresources.”Our level of indebtedness may increase and reduce our financial flexibility.As of December 31, 2015, we had $138.0 million of outstanding borrowings and had $5.2 million of outstanding letters of credit under our revolving creditfacility, $1,144.8 million available for future secured borrowings under our revolving credit facility including pro forma adjustments for the currentborrowing base and the net proceeds from our public equity offering in February 2016 and $2,200.0 million outstanding in senior unsecured notes. Please see“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and capital resources—Senior securedrevolving line of credit” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and capitalresources—Senior unsecured notes.” In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.Our level of indebtedness could affect our operations in several ways, including the following:•a significant portion of our cash flows could be used to service our indebtedness;•a high level of debt would increase our vulnerability to general adverse economic and industry conditions;•the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, paydividends and make certain investments;•our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;•a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to takeadvantage of opportunities that our indebtedness would prevent us from pursuing;•a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay aportion of our then-outstanding bank borrowings; and•a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, generalcorporate or other purposes.A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our levelof indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affectour operations and our future performance. Many of these factors are beyond our control. If oil and natural gas prices remain at their current level for anextended period of time or continue to decline, we may not be able to generate sufficient cash flows to pay the interest on our debt and future workingcapital, and borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through anoffering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we needcapital.In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due toredeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficientfunds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale couldhave a material adverse effect on our business and financial results.29Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOur 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 thefuture, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designatedany of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in thefair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fairvalue 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 mayexpose us to cash margin requirements.Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial conditionor 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 resultin commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties willdepend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of whichare often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Our estimated net provedreserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptionswill materially affect the quantities and present value of our reserves” below. Our cost of drilling, completing and operating wells is often uncertain beforedrilling 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 reserveestimates 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, includingassumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptionscould materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See “Item 1. Business—Ouroperations” for information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net revenues as ofDecember 31, 2015, 2014 and 2013.30Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIn 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 assumptionsabout matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserveinformation 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 andnatural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shownin this Annual Report on Form 10-K. In addition, we may adjust estimates of net proved reserves to reflect production history, results of exploration anddevelopment, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Due to the limited production history of ourundeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than wouldbe 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 ourestimated 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 oiland natural gas reserves. In accordance with SEC requirements for the years ended December 31, 2015, 2014 and 2013, we based the estimated discountedfuture net revenues from our estimated net proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for thepreceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affectedby 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 willaffect 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 fromtime 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. Anysignificant future price changes will have a material effect on the quantity and present value of our estimated net proved reserves.If oil and natural gas prices remain at their current level for an extended period of time or continue to decline, we may be required to take write-downs ofthe 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 theircarrying value may have occurred. In addition, we assess our unproved properties periodically for impairment on a property-by-property basis based onremaining lease terms, drilling results or future plans to develop acreage. Based on specific market factors and circumstances at the time of prospectiveimpairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write downthe 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. The continued decline in oil and natural gas prices since December 31, 2015 may cause us to incurimpairment charges in the future, which could have a material adverse effect on our ability to borrow under our revolving credit facility and our results ofoperations for the periods in which such charges are taken. Due to lower expected future oil prices, we reviewed our proved oil and natural gas properties forimpairment as of December 31, 2015 and 2014. For the year ended December 31, 2015, we recorded an impairment loss of $9.4 million to adjust the carryingvalue of our proved oil and natural gas properties held for sale to their estimated fair value. For the year ended December 31, 2014, we determined that thecarrying value exceeded expected undiscounted cash flows for certain legacy wells that have been producing from conventional reservoirs such as theMadison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations. As a result, we recorded an impairment lossof $40.0 million to adjust the carrying amount of these assets to fair value. No impairment on proved oil and natural gas properties was recorded for the yearended December 31, 2013. During the years ended December 31, 2015, 2014 and 2013, we recorded non-cash impairment31Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentscharges of $36.6 million, $7.3 million and $1.2 million, respectively, on our unproved properties due to expiring leases and periodic assessments of ourunproved properties.The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services or the unavailability of sufficienttransportation for our production could adversely affect our ability to execute our exploration and development plans within our budget and on a timelybasis.Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services or the unavailability of sufficient transportation for ourproduction could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided forin our capital budget, which could have a material adverse effect on our business, financial condition or results of operations. Additionally, compliance withnew or emerging legal requirements that affect midstream operations in North Dakota may reduce the availability of transportation for our production. Forexample, the NDIC adopted regulations in late 2013 that impose more rigorous pipeline development standards on midstream operators, some of whom werely on to construct and operate pipeline infrastructure to transport the oil and natural gas we produce.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 ourexpectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drillingresults 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 serviceproviders in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are notlimited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, runningour 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 facewhile 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 entirelength of the well bore during completion operations, successfully cleaning out the well bore after completion of the final fracture stimulation stage andsuccessfully protecting nearby producing wells from the impact of fracture stimulation.Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Bakken and Three Forks formations beganin late 2009. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and productionprofiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling programbecause of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or oil and natural gas pricesdecline, 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 financingon 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 businessfor the development, exploitation, production and acquisition of oil and natural gas reserves. We spent $610.0 million and $1,572.6 million related to capitalexpenditures for the years ended December 31, 2015 and 2014, respectively. Our capital expenditure budget for 2016 is approximately $400 million, withapproximately $200 million allocated for drilling and completion operations. Since our initial public offering, our capital expenditures have been financedwith proceeds from public equity offerings, proceeds from our $2,200.0 million of senior unsecured notes, borrowings under our revolving credit facility, netcash provided by operating activities, the sale of non-core oil and gas properties and cash settlements of derivative contracts. DeGolyer and MacNaughtonprojects that we will incur capital costs of $828.6 million over the next five years to develop the proved undeveloped reserves in the Williston Basin coveredby its December 31, 2015 reserve report. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a resultof, 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 increase in product prices could result in an increase in our capital expenditures. We intend to finance our future capital expenditures primarilythrough cash flows provided by operating activities, borrowings under our revolving credit facility and cash settlements of derivative contracts; however, ourfinancing needs may require us to alter or increase our capitalization substantially through the issuance of additional debt or equity securities or the sale ofnon-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 thepayment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital32Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsexpenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. In addition, uponthe issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under our revolving credit facility will beautomatically 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;•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 low oil or natural gas prices, operating difficulties, declines inreserves 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 isneeded, 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 ourrevolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of ouroperations 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 netproved reserves, and could adversely affect our business, financial condition and results of operations.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 may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated byothers. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on theoperator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated byour 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 operationsand financial condition.All of our producing properties and operations are located in the Williston Basin region, making us vulnerable to risks associated with operating in onemajor geographic area.As of December 31, 2015, 100% of our proved reserves and production were located in the Williston Basin in northwestern North Dakota and northeasternMontana. As a result, we may be disproportionately exposed to the impact of economics in the Williston Basin or delays or interruptions of production fromthese wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significantgovernmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil ornatural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specificgeographic oil and natural gas producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify theeffect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the sameconditions 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 morediversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.33Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOur 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 ownedby 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 gasmarkets or delay our production” and “Insufficient transportation or refining capacity in the Williston Basin could cause significant fluctuations in ourrealized oil and natural gas prices.” We generally do not purchase firm transportation on third party pipeline facilities, and therefore, the transportation of ourproduction can be interrupted by other customers that have firm arrangements. In addition, these third parties may also impose specifications for the productsthat they are willing to accept. If the total mix of a product fails to meet the applicable product quality specifications, the third parties may refuse to accept allor a part of the products or may invoice us for the costs to handle or damages from receiving the out-of-specification products. In those circumstances, we maybe required to delay the delivery of or find alternative markets for that product, or shut-in the producing wells that are causing the products to be out ofspecification, potentially reducing our revenues.The disruption of third-party facilities due to maintenance, weather or other interruptions of service could also negatively impact our ability to market anddeliver 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 aresulting 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 paidfrom borrowings absent sufficient cash flow. Potential crude oil rail derailments or crashes could also impact our ability to market and deliver our productsand cause significant fluctuations in our realized oil and natural gas prices due to tighter safety regulations imposed on crude-by-rail transportation andinterruptions in service.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 transportationand refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for WTI crude oil. In the past, there have beenperiods when this discount has substantially increased due to the production of oil in the area increasing to a point that it temporarily surpasses the availablepipeline transportation, rail transportation and refining capacity in the area. Recent expansions of both rail and pipeline facilities have reduced the priorconstraint on oil transportation out of the Williston Basin and improved netback pricing received at the lease. In 2015, our price differentials relative to WTIstrengthened as new pipelines opened to eastern Canada and U.S. markets and transportation on rail gradually declined. In the first quarter of 2015, as WTIdeclined, our price differentials increased as a percentage of WTI to a 16% discount but decreased in terms of the dollar per barrel discount to WTI to anaverage of $7.85 per barrel of oil. In the second quarter of 2015, as WTI improved, our price differentials decreased to approximately 10% as a percentage ofWTI and continued to decrease in terms of the dollar per barrel discount to WTI to an average of $5.90 per barrel of oil. In the second half of 2015, while WTIfell again, our price differentials strengthened, decreasing to less than $5.00 per barrel of oil and remaining at approximately 10% as a percentage of WTI. Onbarrels that are transported over pipelines to either Clearbrook, Minnesota or Guernsey, Wyoming, our realized price for crude oil is generally the quotedprice for Bakken crude oil less transportation costs from the point where the crude oil is sold.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 ordelay 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 andsupply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantialpart, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain suchservices 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 unavailabilityof 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 torealize revenue from those wells until other arrangements were made to deliver the products to market.The development of our proved undeveloped reserves in the Williston Basin and other areas of operation may take longer and may require higher levels ofcapital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.34Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsApproximately 32% of our estimated net proved reserves were classified as proved undeveloped as of December 31, 2015. Development of these reserves maytake longer and require higher levels of capital expenditures than we currently anticipate. The future development of our proved undeveloped reserves isdependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as well as access to liquidity sources, such ascapital markets, our revolving credit facility and derivative contracts. Delays in the development of our reserves or increases in costs to drill and developsuch reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result insome projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unprovedreserves.Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial conditionand results of operations.Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our estimated netproved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production ratesthat vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows andincome, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additionalrecoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptablecosts. 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 ofoperations would be adversely affected.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 ourinsurance 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 associatedwith 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 radioactivematerials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gas or other pollutants into theenvironment;•abnormally pressured formations;•shortages of, or delays in, obtaining water for hydraulic fracturing activities;•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.Insurance against all operational risk is not available to us. We are not fully insured against all risks, including development and completion risks that aregenerally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Also, we may electnot to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event that is notfully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.We have incurred losses in 2015 and prior years and may do so again in the future.For the year ended December 31, 2015, we incurred a net loss of $40.2 million. For the years ended December 31, 2014 and 2013, we had net income of$506.9 million and $228.0 million, respectively. Our development of and participation in an35Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsincreasingly larger number of drilling locations has required and will continue to require substantial capital expenditures, including planned capitalexpenditures for 2016 of approximately $400 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 andnatural 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.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 additionalinterpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantitiesto 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 notenable 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 sufficientquantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearingformation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment ofthe 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 andmaterially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations orproducing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Williston Basin may notbe 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 notbe productive.Our potential drilling location inventories are scheduled to be drilled over several years, making them susceptible to uncertainties that could materiallyalter 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 asubstantial 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. Thesepotential drilling locations, including those without proved undeveloped reserves, represent a significant part of our execution strategy. Our ability to drilland develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil andnatural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identifiedwill 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 andguidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years ofthe 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 highlycompetitive 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 notfeasible, 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 suchacreage will expire. As of December 31, 2015, we had leases representing 16,556 net acres expiring in 2016, 8,935 net acres expiring in 2017 and 7,938 netacres expiring in 2018. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonableterms 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 drillingactivities may materially differ from our current expectations, which could adversely affect our business. During the years ended December 31, 2015, 2014and 2013, we recorded non-cash impairment charges of $36.6 million, $7.3 million and $1.2 million on our unproved properties due to expiring leases andperiodic 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 andliabilities.Our oil and natural gas exploration and production operations are subject to stringent federal, regional, state and local laws and regulations governingoccupational 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 conductingdrilling, underground injection or other regulated activities; the restriction on types, quantities and concentration of materials that may be released into theenvironment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the applicationof specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations.Numerous governmental authorities, such as the EPA, and36Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsanalogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, which may cause us toincur significant capital or operating expenditures or costly actions to achieve and maintain compliance. Failure to comply with these laws and regulationsmay result in the assessment of sanctions, including administrative, civil or criminal penalties; the imposition of investigatory, remedial or corrective actionobligations; the occurrence of delays in the development of projects; and the issuance of injunctions limiting or preventing some or all of our operations inaffected areas.There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleumhydrocarbons and wastes, because of air emissions and waste water discharges related to our operations and due to historical industry operations and wastedisposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediationof previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operationswere in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells aredrilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions toenforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Inaddition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our financial conditionor results of well drilling, construction, completion on water management activities or operations. Changes in environmental laws and regulations occurfrequently, and any changes that result in delays or restrictions in the permitting or development of projects or 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 otherwisehave a material adverse effect on our own results of operations, competitive position or financial condition. For example, the NDIC adopted regulations inlate 2013 that impose more rigorous pipeline development standards on midstream operators, some of whom we rely upon to construct and operate pipelineinfrastructure to transport the oil and natural gas we produce. In addition, in 2014, the NDIC adopted legal requirements and implemented a drilling permitreview process that incorporates public review measures for any oil and natural gas wells drilled within buffer zones established around a designated numberof identified areas of interest within the state, including certain National Park or Grassland areas, specified mountains and buttes, certain rivers, and specifiedwildlife management areas. While limited to drilling of wells upon public lands, the drilling permit review process will result in portions of the drillingapplications being made available for public review and comment and could result in a lesser number of such permits being issued or such permits beingissued at a slower rate or with added restrictions, which could impact our overall drilling program. With regard to recent federal laws or regulations, in May2015, the EPA released a final rule that attempted to clarify federal jurisdiction under the Clean Water Act with regards to obtaining permits for dredge andfill activities in wetland areas, the implementation of which has been stayed nationwide due to a number legal challenges, and, in October 2015, the EPAissued a final rule lowering the NAAQS for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. Compliancewith any of these rules or any other new legal requirements could, among other things, require installation of new emission controls on some of ourequipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact ourbusiness.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 mayresult 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 gasproduction 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, aswell as state agencies. In addition, federal laws prohibit market manipulation in connection with the purchase or sale of oil and/or natural gas. Failure tocomply with federal, state and local laws could adversely affect our ability to produce, gather and transport our oil and natural gas and may result insubstantial penalties. Please see “Item 1. Business—Other federal laws and regulations affecting our industry.”Our business involves the selling and shipping by rail of crude oil, including from the Bakken shale, which involves risks of derailment, accidents andliabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition orresults of operations.A portion of our crude oil production is transported to market centers by rail. Recent derailments in North America of trains transporting crude oil havecaused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation byrail of flammable materials. Transportation safety regulators in the United States and Canada are concerned that crude oil from the Bakken shale may be moreflammable than crude oil from other producing regions and are investigating that issue and are also considering changes to existing regulations to address37Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsthose possible risks. In May 2015, PHMSA adopted a final rule that, among other things, imposes a new and enhanced tank car design standard for certaintank cars carrying crude oil and ethanol, a phase out by as early as January 2018 for older DOT-111 tank cars that are not retrofitted, and a classification andtesting program for unrefined petroleum based products, including crude oil. The rule also includes new operational requirements such as routing analyses,speed restrictions and enhanced braking controls. Transport Canada has also issued legal requirements that align with the U.S. May 2015 final rule adoptedby PHMSA, including standards relating to train speed restrictions, route risk analyses and a phase out of non-compliant DOT-111 tank cars.Any changes to existing laws and regulations, or promulgation of new laws and regulations, including any voluntary measures by the rail industry, that resultin new requirements for the design, construction or operation of tank cars used to transport crude oil could increase our costs of doing business and limit ourability to transport and sell our crude oil at favorable prices at market centers throughout the United States, the consequences of which could have a materialadverse effect on our financial condition, results of operations and cash flows.To the extent that new regulations require design changes or other modifications of tank cars, we may incur significant constraints on transportation capacityduring the period while tank cars are being retrofitted or newly constructed to comply with the new regulations. In addition, any derailment of crude oil fromthe Bakken shale involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities.Although we believe that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of anydamages that may arise from such an event.Climate change legislation and regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for theoil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs inpreparing for or responding to those effects.Based on findings by the EPA that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases arecontributing to warming of the Earth’s atmosphere and other climatic changes, the EPA adopted regulations under existing provisions of the CAA thatestablish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential majorsources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet“best available control technology” standards that typically will be established by the states. These or similar permit review requirements could adverselyaffect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. The EPA has also adopted rules requiring themonitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among others, certain onshore oil andnatural gas production facilities, which includes certain of our operations. While from time to time Congress has considered legislation to reduce emissions ofGHGs, 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 ofsuch federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means ofcap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting thoseGHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could imposeadditional direct costs on operations and reduce demand for refined products. The adoption and implementation of any legislation or regulations imposingreporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGsassociated with our operations or could adversely affect demand for the oil and natural gas we produce. For example, in August 2015, the EPA announcedproposed rules, expected to be finalized in 2016, that would establish new controls for methane emissions from certain new, modified or reconstructedequipment and processes in the oil and natural gas source category, including production activities, as part of an overall effort to reduce methane emissionsby up to 45% in 2025. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climatechange agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will useto achieve its GHG emissions targets. It is not possible at this time to predict how new methane restrictions would impact our business or how or when theUnited State might impose restrictions on GHGs as a result of the international agreement agreed to in Paris. The adoption of any legislation or regulationsthat require reporting of GHGs or otherwise restrict emissions of GHGs from the drilling program’s equipment and operations could require us to incurincreased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory orreporting requirements including the imposition of a carbon tax. Finally, it should be noted that some scientists have concluded that increasingconcentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency andseverity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and productionoperations.38Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsFederal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities couldresult 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 rockformations. The process involves the injection of water, sand and chemicals under pressure into the targeted subsurface formations to fracture the surroundingrock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typicallyregulated by state oil and natural gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. Forexample, the EPA issued CAA final regulations in 2012 and proposed additional CAA regulations in August 2015 governing performance standards for theoil and natural gas industry; proposed in April 2015 effluent limitations guidelines that waste water from shale natural gas extraction operations must meetbefore discharging to a treatment plant; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic SubstancesControl Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 thatestablishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands but, in September 2015, the U.S. District Court ofWyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appeal and is being separately appealed by certainenvironmental groups. In addition, from time to time Congress has considered legislation to provide for federal regulation of hydraulic fracturing and torequire disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states have adopted, and other states are consideringadopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturingactivities. States could elect to prohibit hydraulic fracturing altogether, following the lead of the State of New York in 2015. Local government also may seekto adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities inparticular. 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 are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council onEnvironmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Also, the EPA released its draft report on the potentialimpacts of hydraulic fracturing on drinking water resources in June 2015, which report concluded that hydraulic fracturing activities have not led towidespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulicfracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA’s Science Advisory Board provided itscomments on the draft study, indicating its concern that EPA’s conclusion of no widespread, systemic impacts on drinking water sources arising fromfracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The finalversion of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report, when issued, as well as any future studies,depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.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 securetrained 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 suitableproperties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securingequipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of ourcompetitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more forproductive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties andlocations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures ofunsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, andmay be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. Inaddition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attractand 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 tocompete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personneland 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.39Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsTo a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management ortechnical personnel, including Thomas B. Nusz, our Chairman and Chief Executive Officer, and Taylor L. Reid, our 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 theseindividuals.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 andnatural gas activities cannot be conducted as effectively during the winter months. Severe winter weather conditions limit and may temporarily halt ourability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations andmaterially increase our operating and capital costs.The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results.Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production ($96.5 million in receivables atDecember 31, 2015), which we market to energy marketing companies, refineries and affiliates; joint interest receivables ($64.3 million at December 31,2015); and deposits to vendors ($9.7 million at December 31, 2015).We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. This concentration ofcustomers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. For the year endedDecember 31, 2015, sales to Shell Trading (US) Company accounted for approximately 10% of our total sales. For the years ended December 31, 2014 and2013, sales to Musket Corporation accounted for approximately 13% and 11% of our total sales, respectively. No other purchasers accounted for more than10% of our total oil and natural gas sales for the years ended December 31, 2015, 2014 and 2013. We do not require all of our customers to post collateral.The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financialresults.Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily basedon their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells.In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Derivative assets andliabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. AtDecember 31, 2015, we had derivatives in place with eight counterparties and a total net derivative asset of $155.5 million.We may be subject to risks in connection with acquisitions because of uncertainties in evaluating recoverable reserves, well performance and potentialliabilities, as well as uncertainties in forecasting oil and gas prices and future development, production and marketing costs, and the integration ofsignificant acquisitions may be difficult.We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overallbusiness strategy. The successful acquisition of producing properties requires an assessment of several factors, including:•recoverable reserves;•future oil and natural gas prices and their appropriate differentials;•development and operating costs;•potential for future drilling and production;•validity of the seller’s title to the properties, which may be less than expected at the time of signing the purchase agreement; and•potential environmental issues, litigation and other liabilities.The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believeto be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficientlyfamiliar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, andenvironmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may beunwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual40Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsindemnification for environmental liabilities or title defects in excess of the amounts claimed by us before closing and acquire properties on an “as is” basis.Indemnification from the sellers will generally be effective only during a limited time period after the closing and subject to certain dollar limitations andminimums. We may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk thatwe could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results ofoperations or cash flows.Significant acquisitions and other strategic transactions may involve other risks, including:•diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;•the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with thoseof our operations while carrying on our ongoing business;•difficulty associated with coordinating geographically separate organizations;•an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknownliabilities; and•the challenge of attracting and retaining personnel associated with acquired operations.The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior managementmay be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If oursenior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of theintegration process, our business could suffer. In addition, even if we successfully integrate the assets acquired in an acquisition, it may not be possible torealize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipatedfrom an acquisition or realize these benefits within the expected time frame.If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be lower than we expect.The success of a significant acquisition will depend, in part, on our ability to realize anticipated opportunities from combining the acquired assets oroperations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated net provedreserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within theexpected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, in oil and natural gasindustry conditions, by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, failure to retain key personnel, anincrease in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations and stockprice may be adversely affected.We may incur losses as a result of title defects in the properties in which we invest.It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, werely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental officebefore attempting to acquire a lease in a specific mineral interest.Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well toobtain a preliminary title review to ensure there are no obvious defects in the title to the well. Frequently, as a result of such examinations, certain curativework must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects mayadversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects ortitle failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignmentof leasehold rights in properties in which we hold an interest, we will suffer a financial loss.The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negativeeffect 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 participatein that market. The Dodd-Frank Act requires the CFTC, the41Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC hasissued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economicequivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the U.S. DistrictCourt 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 hasfinalized 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-executionrequirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with marginrequirements 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 withcertainty 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 counterpartiesto 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 reportingrequirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivativecontracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivativecontracts, 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 fundcapital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributedto speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if aconsequence 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.Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result ofproposed legislation.President Obama’s budget proposal for fiscal year 2017 recommended the elimination of certain key United States federal income tax preferences currentlyavailable to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentagedepletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination ofthe deduction for United States production activities for oil and gas production, and (iv) the extension of the amortization period for certain geological andgeophysical expenditures. It is unclear whether any such changes or similar changes will be enacted or, if enacted, how soon any such changes could becomeeffective. The passage of this legislation or any other similar changes in U.S. federal income tax law could affect certain tax deductions that are currentlyavailable with respect to oil and gas exploration and production. Any such changes could have an adverse effect on our financial position, results ofoperations and cash flows.Risks Relating to our Common StockWe do not intend to pay, and we are currently prohibited from paying, dividends on our common stock and, consequently, our shareholders’ onlyopportunity to achieve a return on their investment is if the price of our stock appreciates.We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently prohibited from making any cashdividends pursuant to the terms of our revolving credit facility and the indentures governing our senior unsecured notes. Consequently, our shareholders’only opportunity to achieve a return on their investment in us will be if the market price of our common stock appreciates, which may not occur, and theshareholder sells their shares at a profit. There is no guarantee that the price of our common stock will ever exceed the price that the shareholder paid.Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that coulddiscourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.Our amended and restated certificate of incorporation authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board ofDirectors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restatedcertificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change ofcontrol would be beneficial to our stockholders, including:•a classified Board of Directors, so that only approximately one-third of our directors are elected each year;42Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents•limitations on the removal of directors; and•limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals andnominations for elections to the Board of Directors to be acted upon at meetings of stockholders.Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder whobeneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unlessvarious conditions are met, such as approval of the transaction by our Board of Directors.Item 1B. Unresolved Staff CommentsNone.Item 2. PropertiesThe information required by Item 2. is contained in Item 1. Business.Item 3. Legal ProceedingsAlthough we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently aparty to any material legal proceeding other than those noted below. In addition, we are not aware of any material legal or governmental proceedings againstus, or contemplated to be brought against us.On July 6, 2013, a freight train operated by Montreal, Maine and Atlantic Railway (“MMA”) carrying crude oil (the “Train”) derailed in Lac-Mégantic,Quebec. In March 2014, Oasis Petroleum Inc. and Oasis Petroleum LLC (“OP LLC”) were added to a group of over fifty named defendants, including othercrude oil producers as well as the Canadian Pacific Railway, MMA and certain of its affiliates, owners and transloaders of the crude oil carried by the Train,several lessors of tank cars, and the Attorney General of Canada, in a motion filed in the Quebec Superior Court to authorize a class-action lawsuit seekingeconomic, compensatory and punitive damages, as well as costs for claims arising out of the derailment of the Train (Yannick Gagne, etc., et al. v. Rail World,Inc., etc., et al., Case No. 48006000001132) (the “Class-Action”). The motion generally alleges wrongful death and negligence in the failure to provide forthe proper and safe transportation of crude oil.We believe that all claims against Oasis Petroleum Inc. and OP LLC in connection with the derailment of the Train in Lac-Mégantic, Quebec are withoutmerit.On August 7, 2013, MMA filed for bankruptcy protection in the Quebec Superior Court and the United States Bankruptcy Court in Bangor, Maine (together,the “Bankruptcy Actions”). The trustees appointed in the Bankruptcy Actions have negotiated settlement agreements with the majority of the nameddefendants in the Class-Action, including Oasis Petroleum Inc. and OP LLC. The Quebec Superior Court and the United States Bankruptcy Court have issuedorders approving the settlement agreements which were pending before them, and such orders have become final. Pursuant to the settlement agreements,Oasis Petroleum Inc. and OP LLC agreed to contribute to the compensation fund established for those suffering losses as a result of the Lac-Meganticderailment. Such contributions were fully covered by our insurance policies. Furthermore, the settlement agreements bar future litigation against OasisPetroleum Inc. and OP LLC in Canada and the United States arising out of the Lac-Megantic derailment.Item 4. Mine Safety DisclosuresNot applicable.43Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPART IIItem 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity SecuritiesMarket for Registrant’s Common Equity. Our common stock is listed on the NYSE under the symbol “OAS.”The following table sets forth the range of high and low sales prices of our common stock for the two most recent fiscal years as reported by the NYSE: 2015 2014 High Low High Low1st Quarter$19.63 $12.05 $47.28 $38.682nd Quarter$18.86 $14.23 $56.38 $41.013rd Quarter$15.85 $8.04 $58.09 $40.854th Quarter$14.15 $6.34 $41.90 $10.64Holders. As of February 18, 2016, the number of record holders of our common stock was 567. Based on inquiry, management believes that the number ofbeneficial owners of our common stock is approximately 42,300.Dividends. We have not paid any cash dividends since our inception. Covenants contained in our revolving credit facility and the indentures governing oursenior unsecured notes restrict the payment of cash dividends on our common stock. We currently intend to retain all future earnings for the development ofour business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.On February 24, 2016, the last sale price of our common stock, as reported on the NYSE, was $4.53 per share.Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2015.Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the three months endedDecember 31, 2015: PeriodTotalNumber ofSharesExchanged(1) Average PricePaidper Share Total Number of SharesPurchased as Part ofPublicly AnnouncedPlans or Programs Maximum Number (orApproximate Dollar Value) ofShares that May Be PurchasedUnder the Plans or ProgramsOctober 1 – October 31, 20152,283 $9.19 — —November 1 – November 30, 20151,545 11.97 — —December 1 – December 31, 201512,197 11.33 — —Total16,025 $11.09 — —__________________ (1)Represent shares that employees surrendered back to us that equaled in value the amount of taxes needed for payroll tax withholding obligationsupon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our commonstock, nor do we have a publicly announced program to repurchase shares of our common stock.Stock Performance Graph. The following performance graph and related information is “furnished” with the SEC and shall not be deemed “solicitingmaterial” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or theExchange Act, except to the extent that we specifically request that such information be treated as “soliciting material” or specifically incorporate suchinformation by reference into such a filing.The performance graph shown below compares the cumulative total return to our common stockholders as compared to the cumulative total returns on theStandard and Poor’s 500 Index (“S&P 500”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P 500 O&G E&P”) since thetime of our initial public offering. The comparison was prepared based upon the following assumptions:1. $100 was invested in our common stock at its initial public offering price of $14 per share and invested in the S&P 500 and the S&P 500 O&GE&P on June 16, 2010 at the closing price on such date; and44Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents2. Dividends were reinvested.Item 6. Selected Financial DataSet forth below is our summary historical consolidated financial data for the years ended December 31, 2011 through 2015. This information may notbe indicative of our future results of operations, financial position and cash flows and should be read in conjunction with the consolidated financialstatements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” presented elsewhere inthis Annual Report on Form 10-K. We believe that the assumptions underlying the preparation of our historical consolidated financial statements arereasonable. 45Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents Year ended December 31, 2015 2014 2013(1) 2012 2011 (In thousands, except per share data)Statement of operations data: Revenues: Oil and gas revenues$721,672 $1,304,004 $1,084,412 $670,491 $330,422Well services and midstream revenues68,063 86,224 57,587 16,177 —Total revenues789,735 1,390,228 1,141,999 686,668 330,422Expenses: Lease operating expenses(2)144,481 169,600 94,634 54,924 32,707Well services and midstream operating expenses28,031 50,252 30,713 11,774 —Marketing, transportation and gathering expenses31,610 29,133 25,924 9,257 1,365Production taxes69,584 127,648 100,537 62,965 33,865Depreciation, depletion and amortization485,322 412,334 307,055 206,734 74,981Exploration expenses2,369 3,064 2,260 3,250 1,685Rig termination(3)3,895 — — — —Impairment of oil and gas properties(4)46,109 47,238 1,168 3,581 3,610General and administrative expenses92,498 92,306 75,310 57,190 29,435Total expenses903,899 931,575 637,601 409,675 177,648Gain on sale of properties— 186,999 — — (207)Operating income (loss)(114,164) 645,652 504,398 276,993 152,567Other income (expense): Net gain (loss) on derivative instruments210,376 327,011 (35,432) 34,164 1,595Interest expense, net of capitalized interest(149,648) (158,390) (107,165) (70,143) (29,618)Other income (expense)(2,935) 195 1,216 4,860 1,635Total other income (expense)57,793 168,816 (141,381) (31,119) (26,388)Income before income taxes(56,371) 814,468 363,017 245,874 126,179Income tax benefit (expense)16,123 (307,591) (135,058) (92,486) (46,789)Net income (loss)$(40,248) $506,877 $227,959 $153,388 $79,390Earnings (loss) per share: Basic$(0.31) $5.09 $2.45 $1.66 $0.86Diluted(0.31) 5.05 2.44 1.66 0.86__________________ (1)Our statement of operations data for the year ended December 31, 2013 does not include the effects of our 2013 acquisitions for the full twelvemonths of 2013. We acquired such interests on September 26, 2013 and October 1, 2013. See Note 6 to our audited consolidated financial statements.(2)For the year ended December 31, 2011, lease operating expenses exclude marketing, transportation and gathering expenses to conform such amountsto current year classifications. For the years ended December 31, 2012 and 2011, lease operating expenses include midstream income and operatingexpenses, which are included in well services and midstream revenues and well services and midstream operating expenses, respectively, for the yearsended December 31, 2015, 2014 and 2013.(3)During the year ended December 31, 2015, we elected to early terminate certain drilling rig contracts and recorded a rig termination expense of $3.9million.(4)For the years ended December 31, 2015 and 2014, impairment of oil and gas properties includes $9.4 million and $40.0 million, respectively, relatedto our proved properties. See Note 3 to our audited consolidated financial statements.46Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents At December 31, 2015 2014 2013 2012 2011 (In thousands)Balance sheet data: Cash and cash equivalents$9,730 $45,811 $91,901 $213,447 $470,872Net property, plant and equipment5,218,242 5,186,786 4,079,750 2,006,600 1,079,955Total assets(1)5,649,375 5,909,076 4,678,041 2,508,146 1,711,740Long-term debt(1)2,302,584 2,670,664 2,501,687 1,179,352 784,358Total stockholders’ equity2,319,342 1,872,301 1,348,549 795,005 634,238 __________________ (1)Prior to 2015, we presented deferred financing costs related to our senior unsecured notes in other assets on our Consolidated Balance Sheet. Upon theadoption of new accounting guidance in 2015, such costs are presented as a deduction from the carrying value of long-term debt. As of December 31,2015, deferred financing costs related to our senior unsecured notes totaling $35.4 million were included in long-term debt on our ConsolidatedBalance Sheet. Prior periods have been adjusted retrospectively to reflect the period-specific effects of applying the new guidance. Reclassifiedamounts total $29.3 million, $33.9 million, $20.6 million and $15.6 million for the years ended December 31, 2014, 2013, 2012 and 2011,respectively. Year ended December 31, 2015 2014 2013 2012 2011 (In thousands)Other financial data: Net cash provided by operating activities$359,815 $872,516 $697,856 $392,386 $176,024Net cash used in investing activities(479,148) (1,077,452) (2,445,076) (1,038,605) (629,390)Net cash provided by financing activities83,252 158,846 1,625,674 388,794 780,71847Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsItem 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financialstatements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements”that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefsabout future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors which could cause actual resultsto vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions,uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance ofproducing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportationfacilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well asthose factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertaintiesand assumptions, the forward-looking events discussed may not occur. See “Cautionary note regarding forward-looking statements.”OverviewWe are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resourcesprimarily in the North Dakota and Montana regions of the Williston Basin. Since our inception, we have acquired properties that provide current productionand significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us withrepeatable successes in the Bakken and Three Forks formations. OPNA conducts our domestic oil and natural gas exploration and production activities. Wealso operate a well services business through OWS and a midstream services business through OMS, both of which are separate reportable business segmentsthat are complementary to our primary development and production activities. The revenues and expenses related to work performed by OWS and OMS forOPNA’s working interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities asmarket conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. We built our WillistonBasin assets through acquisitions and development activities, which were financed with a combination of capital from private investors, borrowings underour revolving credit facility, cash flows provided by operating activities, proceeds from our senior unsecured notes, proceeds from our public equityofferings, the sale of non-core oil and gas properties and cash settlements of derivative contracts. For acquisitions of properties with additional development,exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing andimplementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of returneither because they provided an entry into a new area of interest or complemented our existing operations. We intend to continue to acquire both operatedand non-operated properties to the extent we believe they meet our return objectives. In addition, the acquisition of non-operated properties in new areasprovides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis.Due to the geographic concentration of our oil and natural gas properties in the Williston Basin, we believe the primary sources of opportunities, challengesand risks related to our business for both the short and long-term are:•commodity prices for oil and natural gas;•transportation capacity;•availability and cost of services; and•availability of qualified personnel.Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatorydevelopments as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in thefuture. Crude oil prices have declined significantly since mid-2014. As a result of sustained low oil prices, we have decreased our planned 2016 capitalexpenditures as compared to 2015, and we are continuing to concentrate our drilling activities in certain areas that are the most economic in the WillistonBasin. Extended periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, thequantities of oil and natural gas reserves that we can economically produce and our access to capital.Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and naturalgas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities,commodity prices have experienced significant fluctuations. The current global oversupply of crude oil has caused a sharp decline in oil prices since mid-2014. We enter into crude oil sales contracts with purchasers who have access to crude oil transportation capacity, utilize derivative financial instruments tomanage our commodity price risk and enter into physical delivery contracts to manage our price differentials. In an effort to improve price realizations48Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsfrom 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 gasto 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 oilor natural gas customer would have a material adverse effect on our results of operations or cash flows. Additionally, we sell a significant amount of our crudeoil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reducethe need to transport barrels by truck from the wellhead. As of December 31, 2015, we were flowing over 80% of our gross operated oil production throughthese gathering systems. Please see “Item 1. Business—Marketing, transportation and major customers.”Our quarterly average net realized oil prices and average price differentials are shown in the tables below. 2015 Year endedDecember 31, 2015 Q1 Q2 Q3 Q4 Average Realized Oil Prices ($/Bbl)(1)$40.73 $52.04 $41.61 $37.77 $43.04Average Price Differential(2)16% 10% 10% 10% 12% 2014 Year endedDecember 31, 2014 Q1 Q2 Q3 Q4 Average Realized Oil Prices ($/Bbl)(1)$89.66 $94.48 $87.17 $62.79 $82.73Average Price Differential(2)9% 8% 10% 13% 10% 2013 Year endedDecember 31, 2013 Q1 Q2 Q3 Q4 Average Realized Oil Prices ($/Bbl)(1)$93.33 $91.15 $100.75 $85.87 $92.34Average Price Differential(2)1% 3% 5% 12% 6%__________________ (1)Realized oil prices do not include the effect of derivative contract settlements.(2)Price differential reflects the difference between realized oil prices and WTI crude oil index prices.Changes in commodity prices may also significantly affect the economic viability of drilling projects as well as the economic valuation and economicrecovery of oil and gas reserves. Crude oil produced and sold in the Williston Basin has historically sold at a discount to WTI due to transportation costs andtakeaway capacity. In the past, there have been periods when this discount has substantially increased due to oil production in the area increasing to a pointthat it temporarily surpasses the available pipeline transportation, rail transportation and refining capacity in the area. Recent expansions of both rail andpipeline facilities have reduced the prior constraint on oil transportation out of the Williston Basin and improved netback pricing received at the lease. Inearly 2013, our average price differentials relative to WTI narrowed, primarily due to our ability to access premium coastal markets by rail. As the premiumreceived in coastal markets contracted during the second and third quarters of 2013, our average price differentials relative to WTI increased. In the fourthquarter of 2013 and into the first quarter of 2014, our average price differentials relative to WTI continued to increase due to the pipeline market weakeningas a result of refinery down time and increased U.S. and Canadian production. In the second and third quarters of 2014, stronger pipeline prices shifted moreof our barrels towards the pipelines, but rail buyers had to compete with pipeline prices despite weaker Brent differentials, resulting in price differentialsrelative to WTI of approximately 9% to 11%. In the fourth quarter of 2014, as WTI crude oil prices declined, our price differentials increased as a percentageof WTI but remained relatively flat in terms of the dollar per barrel discount to WTI in the range of $9.00 to $10.50 per barrel of oil. In 2015, our pricedifferentials relative to WTI strengthened as new pipelines opened to eastern Canada and U.S. markets and transportation on rail gradually declined. In thefirst quarter of 2015, as WTI further declined, our price differentials continued to increase as a percentage of WTI but decreased in terms of the dollar perbarrel discount to WTI to an average of $7.85 per barrel of oil. In the second quarter of 2015, as WTI improved, our price differentials returned toapproximately 10% as a percentage of WTI and continued to decrease in terms of the dollar per barrel discount to WTI to an average of $5.90 per barrel of oil.In the second half of 2015, while WTI fell again, our price differentials strengthened, decreasing to less than $5.00 per barrel of oil and remaining atapproximately 10% as a percentage of WTI. Our market optionality on the crude oil gathering systems allows us to shift volumes between pipeline and railmarkets in order to optimize price realizations.We believe our large concentrated acreage position provides us with a multi-year inventory of drilling projects and requires forward planning visibility forobtaining services and necessary permits to drill wells. As a result of lower future oil price expectations, we are continuing to slow the pace of development in2016, and plan to reduce our well completions from 80 gross (62.4 net) operated wells in 2015 to 46 gross (28.6 net) operated wells in 2016. Additionally, westarted completing 100% of our wells with OWS in February 2015 and have the ability to control the pace of completions to allow for additional financialflexibility. In 2015, we wrote off $22.2 million of leases that we do not expect to develop before their 2016 and 2017 contract expirations, as we continue tofocus our 2016 drilling activities in the deepest part of our acreage in the Williston Basin.49Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOur 2015, 2014 and 2013 activities included development and exploration drilling in the Williston Basin. Our current activities are focused on evaluatingand developing our asset base and optimizing our operations. Based on the reserve reports prepared by our independent reserve engineers, we had 218.2MMBoe of estimated net proved reserves with a PV-10 of $2,022.7 million and a Standardized Measure of $1,914.3 million at December 31, 2015, 272.1MMBoe of estimated net proved reserves with a PV-10 of $5,481.4 million and a Standardized Measure of $3,981.7 million at December 31, 2014 and 227.9MMBoe of estimated net proved reserves with a PV-10 of $5,486.9 million and a Standardized Measure of $3,727.6 million at December 31, 2013. Ourestimated 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 for the years ended December 31, 2015, 2014 and 2013 were $50.16/Bbl for oil and $2.63/MMBtu for naturalgas, $95.28/Bbl for oil and $4.35/MMBtu for natural gas and $96.96/Bbl for oil and $3.66/MMBtu for natural gas, respectively. These prices were adjustedby lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at thewellhead. Future operating costs, production taxes and capital costs were based on current costs as of each year-end. As of February 8, 2016, the spot crude oilprice was $29.71 per barrel, a 20% decrease since December 31, 2015 and a 39% decrease as compared to an average WTI of $48.75 per barrel during the yearended December 31, 2015. An extended period of low oil prices could result in a significant decrease in our estimated net proved reserves and related futurenet revenues, PV-10 and Standardized Measure in the future.Forward commodity prices and estimates of future production also play a significant role in determining impairment of proved oil and natural gasproperties. As a result of lower commodity prices and their impact on our estimated future cash flows, we have continued to review our proved oil and naturalgas properties for impairment. In 2014, we recorded a proved impairment loss of $40.0 million due to lower expected future oil prices, and in 2015, werecorded an impairment loss of $9.4 million to write down our proved properties held for sale to their estimated fair value. No other proved impairmentcharges were recorded during the year ended December 31, 2015, although the difference between the expected undiscounted future cash flows and thecarrying value of our proved oil and natural gas properties in the Bakken and Three Forks formations has narrowed to $1,264.8 million as of December 31,2015, a decrease of approximately 56% as compared to December 31, 2014. The underlying commodity prices embedded in our estimated cash flows weredetermined using NYMEX forward swap prices for five years, escalating 3% per year thereafter effective as of December 31, 2015 and holding the fifth yearprice constant thereafter as of December 31, 2014. Effective as of December 31, 2015, a 3% inflation factor was also applied to the future operating anddevelopment costs after five years. Expected future oil and natural gas prices have continued to decline in early 2016. As of February 12, 2016, the averagefive-year WTI strip price was $43.70 per barrel, a 10% decrease as compared to the average five-year WTI strip price as of December 31, 2015, which reducesthe excess of the expected undiscounted cash flows over the carrying value of our proved oil and natural gas properties in the Bakken and Three Forksformations to $327.2 million. If expected future oil prices decline by 13% as compared to December 31, 2015, holding all other factors constant, the expectedundiscounted cash flows may not exceed the carrying value of our proved oil and natural gas properties in the Bakken and Three Forks formations, and as aresult, we may recognize additional proved impairment charges in the future, and such impairment charges could exceed $2,500.0 million assuming adiscount rate of 10%.2015 Highlights•We increased average daily production by 11% to 50,477 Boe per day in 2015 from 45,656 Boe per day in 2014.•We completed and placed on production 80 gross (62.4 net) operated wells during 2015. As of December 31, 2015, the Company had 85 grossoperated wells awaiting completion.•Capital expenditures were $610.0 million for the year ended December 31, 2015, a 61% decrease as compared to 2014 capital expenditures.•We had estimated net proved oil and natural gas reserves at December 31, 2015 of 218.2 MMBoe, of which 85% consisted of oil and 68% wereclassified as proved developed.•We ended the year with a leasehold position of 484,745 total net acres in the Williston Basin, primarily targeting the Bakken and Three Forksformations. In addition, we increased our acreage that is held by production to 442,292 net acres as of December 31, 2015.•At December 31, 2015, we had $9.7 million of cash and cash equivalents and had total pro forma liquidity of $1,199.4 million, includingadjustments for the current borrowing base and the net proceeds from our public equity offering in February 2016 (see “Liquidity and capitalresources” below).Results of OperationsRevenuesOur oil and gas revenues are derived from the sale of oil and natural gas production. These revenues do not include the effects of derivative instruments andmay vary significantly from period to period as a result of changes in volumes of production sold50Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsor changes in commodity prices. Our well services and midstream revenues are primarily derived from well completion activity, tool rentals, salt waterpipeline transport, salt water disposal and fresh water sales for third-party working interest owners in OPNA’s operated wells. Intercompany revenues for workperformed by OWS and OMS for OPNA’s working interests are eliminated in consolidation.The following table summarizes our revenues and production data for the periods presented: Year ended December 31, 2015 2014 2013Operating results (in thousands): Revenues Oil$692,497 $1,231,251 $1,033,866Natural gas29,175 72,753 50,546Well services44,294 74,610 51,845Midstream23,769 11,614 5,742Total revenues$789,735 $1,390,228 $1,141,999Production data: Oil (MBbls)16,091 14,883 11,133Natural gas (MMcf)14,002 10,691 7,450Oil equivalents (MBoe)18,424 16,664 12,375Average daily production (Boe per day)50,477 45,656 33,904Average sales prices: Oil, without derivative settlements (per Bbl)(1)$43.04 $82.73 $92.34Oil, with derivative settlements (per Bbl)(1)(2)66.06 83.19 91.61Natural gas (per Mcf)(3)2.08 6.81 6.78__________________ (1)For the year ended December 31, 2013, average sales prices for oil is calculated using total oil revenues, excluding bulk oil sales of $5.8 million,divided by oil production.(2)Realized prices include gains or losses on cash settlements for our commodity derivatives, which do not qualify for and were not designated ashedging instruments for accounting purposes. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periodspresented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.(3)Natural gas prices include the value for natural gas and natural gas liquids.Year ended December 31, 2015 as compared to year ended December 31, 2014Total revenues. Our total revenues decreased $600.5 million, or 43%, to $789.7 million during the year ended December 31, 2015 as compared to the yearended December 31, 2014, primarily due to lower realized oil and natural gas sales prices, partially offset by increased production volumes sold. Our averagerealized prices for oil and natural gas decreased by 48% and 69%, respectively, during the year ended December 31, 2015 as compared to December 31, 2014.Net production volumes for the year ended December 31, 2015 were 18,424 MBoe, an 11% increase from net production of 16,664 MBoe for the year endedDecember 31, 2014. Our net production volumes increased 1,760 MBoe over 2014 primarily due to a successful operated and non-operated drilling andcompletion program.Oil and gas revenues. Our primary revenues are a function of oil and natural gas production volumes sold and average sales prices received for thosevolumes. Average daily production sold increased by 4,821 Boe per day, or 11%, to 50,477 Boe per day during the year ended December 31, 2015 ascompared to the year ended December 31, 2014. The increase in average daily production sold was primarily a result of our 64.3 total net well completions inthe Williston Basin during 2015, offset by the natural decline in production in wells that were producing as of December 31, 2014. Production from wellscompleted contributed to average daily production during 2015 by approximately 11,366 Boe per day. Average oil sales prices, without derivativesettlements, decreased by $39.69 per barrel, or 48%, to an average of $43.04 per barrel, and average natural gas sales prices, which include the value fornatural gas and natural gas liquids, decreased by $4.73 per Mcf to an average of $2.08 per Mcf for the year ended December 31, 2015 as compared to the yearended December 31, 2014. The lower oil and natural gas sales prices decreased revenues by $641.2 million, partially offset by higher production amountssold, which increased revenues by $58.9 million during the year ended December 31, 2015. As of February 8, 2016, the spot crude oil price was $29.71 perbarrel, a 20% decrease since December 31, 2015 and a 39% decrease as compared to an average WTI of $48.75 per51Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsbarrel during the year ended December 31, 2015. Extended current low commodity prices could result in a significant decrease in our oil and gas volumesand revenues in the future.Well services and midstream revenues. Well services revenues decreased $30.3 million for the year ended December 31, 2015 as compared to the yearended December 31, 2014 primarily due to a $26.8 million decrease in well completion product sales to third parties as a result of OWS completingsubstantially all of OPNA’s operated wells in 2015, coupled with a decrease of $3.1 million in tool rentals as a result of running fewer rigs in 2015 ascompared to 2014. Well completion activity increased year over year, but OWS completed OPNA wells with a lower average third-party working interest in2015 as compared to 2014, resulting in a net decrease of $0.3 million in well completion revenue. While a lower average third-party working interestdecreases the well completion revenue recognized in our consolidated results of operations, it improves our capital expenditures by reducing OPNA wellcosts. Midstream revenues totaled $23.8 million for the year ended December 31, 2015, a $12.2 million increase year over year, primarily due to a $9.1million increase in salt water disposal revenue due to increased water volumes flowing through our salt water disposal systems as a result of increased wellconnections and capacity additions in areas that previously had bottlenecks coupled with a $1.9 million increase in fresh water sales revenue.Year ended December 31, 2014 as compared to year ended December 31, 2013Total revenues. Our total revenues increased $248.2 million, or 22%, to $1,390.2 million during the year ended December 31, 2014 as compared to the yearended December 31, 2013, primarily due to increased production volumes sold, partially offset by lower realized oil sales prices. Net production volumes forthe year ended December 31, 2014 were 16,664 MBoe, a 35% increase from net production of 12,375 MBoe for the year ended December 31, 2013. Our netproduction volumes increased 4,289 MBoe over 2013 primarily due to a successful operated and non-operated drilling and completion program.Oil and gas revenues. Our primary revenues are a function of oil and natural gas production volumes sold and average sales prices received for thosevolumes. Average daily production sold increased by 11,752 Boe per day, or 35%, to 45,656 Boe per day during the year ended December 31, 2014 ascompared to the year ended December 31, 2013. The increase in average daily production sold was primarily a result of our 151.1 total net well completionsin the Williston Basin during 2014 and our acquisitions of oil and natural gas properties in the Williston Basin in the second half of 2013 (the “2013Acquisitions”), offset by the natural decline in production in wells that were producing as of December 31, 2013 and the Sanish Divestiture. Production fromwells completed contributed to average daily production during 2014 by approximately 13,805 Boe per day. The Sanish Divestiture in the first quarter of2014 resulted in a decrease in average daily production of approximately 2,308 Boe per day during 2014. Average oil sales prices, without derivativesettlements, decreased by $9.61 per barrel, or 10%, to an average of $82.73 per barrel, and average natural gas sales prices, which include the value for naturalgas and natural gas liquids, increased slightly by $0.03 per Mcf to an average of $6.81 per Mcf for the year ended December 31, 2014 as compared to the yearended December 31, 2013. The higher production amounts sold increased revenues by $332.2 million, partially offset by lower oil sales prices, whichdecreased revenues by $107.0 million during the year ended December 31, 2014. In addition, bulk oil sales related to marketing activities included in oilrevenues decreased $5.8 million during the year ended December 31, 2014 as compared to the year ended December 31, 2013.Well services and midstream revenues. Well services revenues increased $22.8 million for the year ended December 31, 2014 as compared to the yearended December 31, 2013 due to an increase in well completion activity as a result of adding a second OWS fracturing fleet in 2014, coupled with increasedwell completion product sales and tool rentals. Midstream revenues totaled $11.6 million for the year ended December 31, 2014, a $5.9 million increase yearover year, primarily due to increased water volumes flowing through our salt water disposal systems and fresh water sales.52Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExpenses and other incomeThe following table summarizes our operating expenses, gain on sale of properties and other income and expenses for the periods presented: Year ended December 31, 2015 2014 2013 (In thousands, except per Boe of production)Expenses: Lease operating expenses(1)$144,481 $169,600 $94,634Well services and midstream operating expenses28,031 50,252 30,713Marketing, transportation and gathering expenses31,610 29,133 25,924Production taxes69,584 127,648 100,537Depreciation, depletion and amortization485,322 412,334 307,055Exploration expenses2,369 3,064 2,260Rig termination3,895 — —Impairment of oil and gas properties46,109 47,238 1,168General and administrative expenses92,498 92,306 75,310Total expenses903,899 931,575 637,601Gain on sale of properties— 186,999 —Operating income (loss)(114,164) 645,652 504,398Other income (expense): Net gain (loss) on derivative instruments210,376 327,011 (35,432)Interest expense, net of capitalized interest(149,648) (158,390) (107,165)Other income (expense)(2,935) 195 1,216Total other income (expense)57,793 168,816 (141,381)Income before income taxes(56,371) 814,468 363,017Income tax benefit (expense)16,123 (307,591) (135,058)Net income (loss)$(40,248) $506,877 $227,959Costs and expenses (per Boe of production): Lease operating expenses(1)$7.84 $10.18 $7.65Marketing, transportation and gathering expenses1.72 1.75 2.09Production taxes3.78 7.66 8.12Depreciation, depletion and amortization26.34 24.74 24.81General and administrative expenses5.02 5.54 6.09__________________ (1)For the year ended December 31, 2013, lease operating expenses include midstream income and operating expenses, which are included in wellservices and midstream revenues and well services and midstream operating expenses, respectively, for the years ended December 31, 2015 and 2014.Year ended December 31, 2015 as compared to year ended December 31, 2014Lease operating expenses. Lease operating expenses decreased $25.1 million to $144.5 million for the year ended December 31, 2015 as compared to theyear ended December 31, 2014. This decrease was primarily due to lower workover costs and an increase in salt water disposal volumes being transported onOMS pipelines and injected in OMS salt water disposal wells, partially offset by higher costs associated with operating an increased number of producingwells. We completed and placed on production 64.3 total net wells in the Williston Basin during the year ended December 31, 2015 as compared to 151.1total net wells completed and placed on production during the year ended December 31, 2014. Lease operating expenses decreased from $10.18 per Boe forthe year ended December 31, 2014 to $7.84 per Boe for the year ended December 31, 2015 due to the lower costs and increase in oil and natural gasproduction.Well services and midstream operating expenses. Well services and midstream operating expenses represent third-party working interest owners’ share ofcompletion service costs, cost of goods sold and operating expenses incurred by OWS and53Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOMS. The $22.2 million decrease for the year ended December 31, 2015 as compared to the year ended December 31, 2014 was attributable to a $23.8million decrease in well completion costs as a result of lower well completion product sales to third parties due to OWS completing substantially all ofOPNA’s operated wells, coupled with OWS completing OPNA wells with a lower average third-party working interest in the year ended December 31, 2015 ascompared to December 31, 2014. This decrease was partially offset by a $1.6 million increase related to midstream operating expenses and fresh waterpurchases.Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $2.5 million year over year, or a $0.03decrease per Boe, which was primarily attributable to a $1.4 million increase in gas gathering charges related to additional well connections on OMSinfrastructure, a $1.4 million increase in oil transportation costs associated with having additional wells connected to third-party infrastructure and a $0.3million increase in our pipeline imbalance. These increases were partially offset by a decrease year over year of $0.9 million in the write down of our linefillinventory to the lower of cost or market value at year-end. Excluding non-cash valuation adjustments, our marketing, transportation and gathering expenseson a per Boe basis would have remained constant at $1.62 and $1.61 for the years ended December 31, 2015 and 2014, respectively. The transporting ofvolumes through third-party oil gathering pipelines increases marketing, transportation and gathering expenses but improves oil price realizations byreducing transportation costs included in our oil price differential for sales at the wellhead.Production taxes. Our production taxes for the years ended December 31, 2015 and 2014 were 9.6% and 9.8%, respectively, as a percentage of oil and naturalgas sales. The production tax rate decreased slightly year over year primarily due to reduced extraction tax rates triggered by lower oil prices on certain NorthDakota wells, partially offset by an increased weighting of wells in North Dakota, which has a higher average production tax rate as compared to Montana.For the years ended December 31, 2015 and 2014, the percentage of our total production located in North Dakota was approximately 88% and 86%,respectively. In 2015 and 2014, North Dakota had a crude oil tax structure based on a 5% production tax and a 6.5% oil extraction tax, resulting in acombined tax rate of 11.5% of crude oil revenues. In 2016, the North Dakota oil extraction tax will be reduced to 5%, resulting in a 10% combined tax rate,which will rise by 0.5% if crude oil prices average above $90 per barrel for three consecutive months.Depreciation, depletion and amortization (“DD&A”). DD&A expense increased $73.0 million to $485.3 million for the year ended December 31, 2015 ascompared to the year ended December 31, 2014. The increase in DD&A expense for the year ended December 31, 2015 was primarily due to an increase in theaverage DD&A rate per Boe year over year coupled with production increases from our wells completed during 2015. The DD&A rate for the year endedDecember 31, 2015 was $26.34 per Boe as compared to $24.74 per Boe for the year ended December 31, 2014. The increase in the DD&A rate was primarilydue to lower recoverable reserves related to lower oil and natural gas prices and increased exploratory and delineation drilling in the Three Forks formation.Rig termination. As a result of our lowered 2015 capital expenditure program, we elected to early terminate certain drilling rig contracts and recorded a rigtermination expense of $3.9 million for the year ended December 31, 2015. We did not elect to early terminate any drilling rig contracts during the yearended December 31, 2014 or 2013.Impairment of oil and gas properties. Due to lower expected future oil prices, we reviewed our proved oil and natural gas properties for impairment as ofDecember 31, 2015 and 2014. For the year ended December 31, 2015, we recorded an impairment loss of $9.4 million to adjust the carrying value of ourproved oil and natural gas properties held for sale to their estimated fair value. For the year ended December 31, 2014, we determined that the carrying valueexceeded expected undiscounted cash flows for certain legacy wells that have been producing from conventional reservoirs such as the Madison, Red Riverand other formations in the Williston Basin other than the Bakken or Three Forks formations. As a result, we recorded an impairment loss of $40.0 million toadjust the carrying amount of these assets to fair value. During the years ended December 31, 2015 and 2014, we also recorded non-cash impairment chargesof $36.6 million and $7.3 million, respectively, for unproved properties due to leases that expired during the period and periodic assessments of unprovedproperties. The 2015 and 2014 impairment charges included $22.2 million related to acreage expiring in 2016 and 2017 and $2.9 million related to acreageexpiring in 2015 and 2016, respectively, as a result of periodic assessments because there were no plans to drill or extend the leases prior to their expiration.In determining the amount of non-cash impairment charges for such periods, we considered the application of the factors described under “Criticalaccounting policies and estimates—Impairment of proved properties” and “Critical accounting policies and estimates—Impairment of unproved properties.”General and administrative (“G&A”) expenses. Our G&A expenses increased $0.2 million to $92.5 million for the year ended December 31, 2015 ascompared to the year ended December 31, 2014. E&P G&A was $83.0 million and $80.4 million for the years ended December 31, 2015 and 2014,respectively. The $2.6 million increase in E&P G&A was primarily due to increased employee compensation expenses, partially offset by increased sharedservices allocations to our OWS and OMS segments. OMS G&A increased $1.3 million for the year ended December 31, 2015 as compared to December31, 2014 primarily due to increased employee compensation due to organizational growth within this segment. OWS G&A decreased by $3.6 million54Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsprimarily due to OWS completing OPNA wells with a lower average third-party working interest in the year ended December 31, 2015 as compared to 2014.Consolidated G&A expenses included non-cash amortization for stock-based compensation of $25.3 million and $21.3 million in 2015 and 2014,respectively. While our full-time employee headcount decreased to 535 as of December 31, 2015 from 558 as of December 31, 2014, our average employeeheadcount was higher during 2015 as compared to 2014.Gain on sale of properties. No gain or loss on sale of properties was recorded in the year ended December 31, 2015. In the year ended December 31, 2014, werecognized a $187.0 million gain related to the Sanish Divestiture.Derivatives. As a result of entering into derivative contracts and the effect of the forward strip oil price changes, we incurred a $210.4 million net gain onderivative instruments, including net cash settlement receipts of $370.4 million, for the year ended December 31, 2015, and a $327.0 million net gain onderivative instruments, including net cash settlement receipts of $6.8 million, for the year ended December 31, 2014. Cash settlements represent thecumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modifythe derivative instruments that were settled.Interest expense. Interest expense decreased $8.7 million to $149.6 million for the year ended December 31, 2015 as compared to the year endedDecember 31, 2014. The decrease was primarily due to increased interest costs capitalized due to increased work in progress, including the natural gasprocessing plant we are constructing in Wild Basin and 85 wells waiting on completion as of December 31, 2015. Interest expense incurred on borrowingsunder our revolving credit facility remained relatively constant during 2015 as compared to 2014. For the year ended December 31, 2015, the weightedaverage debt outstanding under our revolving credit facility was $261.2 million and the weighted average interest rate incurred on the outstandingborrowings was 1.8%. For the year ended December 31, 2014, the weighted average debt outstanding under our revolving credit facility was $272.3 millionand the weighted average interest rate incurred on the outstanding borrowings was 1.8%. We capitalized $18.6 million and $8.8 million of interest costs forthe years ended December 31, 2015 and 2014, respectively, which will be amortized over the life of the related assets.Income tax benefit (expense). Income tax benefit for the year ended December 31, 2015 was recorded at 28.6% of pre-tax loss, and income tax expense for theyear ended December 31, 2014 was recorded at 37.8% of pre-tax net income. While our 2014 effective tax rate was consistent with the statutory tax rateapplicable to the U.S. and the blended state rate for the states in which we conduct business, our effective tax rate for the year ended December 31, 2015 waslower due to permanent differences between the amounts expensed for book purposes versus the amounts deductible for income tax purposes related to stock-based compensation vesting during the year ended December 31, 2015 at stock prices lower than the grant date values, partially offset by a reduction in theNorth Dakota statutory tax rate in 2015.Year ended December 31, 2014 as compared to year ended December 31, 2013Lease operating expenses. Lease operating expenses increased $75.0 million to $169.6 million for the year ended December 31, 2014 as compared to the yearended December 31, 2013. This increase was primarily due to the costs associated with operating an increased number of producing wells and associatedproduced fluid volumes as a result of our 2014 well completions and the 2013 Acquisitions, as well as increased workover costs, which include certain coststo protect producing wells from wells that are being completed. We completed and placed on production 151.1 total net wells in the Williston Basin duringthe year ended December 31, 2014 as compared to 115.1 total net wells completed and placed on production during the year ended December 31, 2013.Lease operating expenses increased from $7.65 per Boe for the year ended December 31, 2013 to $10.18 per Boe for the year ended December 31, 2014.Well services and midstream operating expenses. Well services and midstream operating expenses represent third-party working interest owners’ share ofcompletion service costs, cost of goods sold and operating expenses incurred by OWS and OMS. The $19.5 million increase for the year ended December 31,2014 as compared to the year ended December 31, 2013 was attributable to a $16.3 million increase from OWS’ well completion activity and wellcompletion product sales and a $3.2 million increase related to midstream operating expenses.Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $3.2 million year over year, or a $0.34decrease per Boe, which was primarily attributable to increased oil transportation costs associated with having additional wells connected to third-partyinfrastructure and a $0.9 million increase due to an increase in the lower of cost or market adjustment on our linefill inventory partially offset by a decrease inthe pipeline imbalance accrual. In addition, there was a $5.8 million decrease in costs related to bulk oil purchases. Excluding non-cash valuationadjustments and bulk oil purchase costs, our marketing, transportation and gathering expenses on a per Boe basis would have been $1.61 and $1.52 for theyears ended December 31, 2014 and 2013, respectively. The transporting of volumes through third-party oil gathering pipelines increases marketing,transportation and gathering expenses but improves oil price realizations by reducing transportation costs included in our oil price differential for sales at thewellhead.55Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsProduction taxes. Our production taxes for the years ended December 31, 2014 and 2013 were 9.8% and 9.3%, respectively, as a percentage of oil and naturalgas sales. The 2014 production tax rate was higher than the 2013 production tax rate primarily due to the increased weighting of wells in North Dakota,which has higher production tax rates as compared to Montana. For the years ended December 31, 2014 and 2013, the percentage of our total productionlocated in North Dakota was approximately 86% and 82%, respectively, with an average production tax rate of approximately 11%.Depreciation, depletion and amortization. DD&A expense increased $105.3 million to $412.3 million for the year ended December 31, 2014 as compared tothe year ended December 31, 2013. The increase in DD&A expense for the year ended December 31, 2014 was primarily a result of our production increasesfrom our wells completed during 2014 and the 2013 Acquisitions. The DD&A rate for the year ended December 31, 2014 was $24.74 per Boe as compared to$24.81 per Boe for the year ended December 31, 2013. In the first two months of 2014, we had production from the wells sold in the Sanish Divestiture, butthese wells were not depreciated because the assets were classified as held for sale, which lowered DD&A by $0.18 per Boe for the year ended December 31,2014. Excluding the impact of the Sanish Divestiture, the increase in the DD&A rate was primarily due to the 2013 Acquisitions coupled with an increase inthe drilling program into the Three Forks formation, offset by continued reductions to well costs.Impairment of oil and gas properties. Due to lower expected future oil prices, we reviewed our proved oil and natural gas properties for impairment as ofDecember 31, 2014 and determined that the carrying value exceeded the expected undiscounted cash flows for certain legacy wells that have been producingfrom conventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations.As a result, we recorded an impairment loss of $40.0 million to adjust the carrying amount of these assets to fair value. No impairment of proved oil andnatural gas properties was recorded for the year ended December 31, 2013. During the years ended December 31, 2014 and 2013, we also recorded non-cashimpairment charges of $7.3 million and $1.2 million, respectively, for unproved properties due to leases that expired during the period and periodicassessments of unproved properties. The 2014 impairment charge included $2.9 million related to acreage expiring in 2015 and 2016 as a result of a periodicassessment because there were no plans to drill or extend the leases prior to their expiration. In 2013, we did not record any impairment charges as a result ofperiodic assessments based on our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leasesthat would otherwise expire. In determining the amount of non-cash impairment charges for such periods, we considered the application of the factorsdescribed under “Critical accounting policies and estimates—Impairment of proved properties” and “Critical accounting policies and estimates—Impairmentof unproved properties.”General and administrative expenses. Our G&A expenses increased $17.0 million for the year ended December 31, 2014 from $75.3 million for the yearended December 31, 2013. E&P G&A was $80.4 million and $68.8 million for the years ended December 31, 2014 and 2013, respectively. The $11.6 millionincrease in E&P G&A was primarily due to the impact of our organizational growth on employee compensation, partially offset by increased shared servicesallocations to the OWS and OMS segments. OWS G&A increased by $4.7 million primarily as a result of adding a second OWS fracturing fleet in 2014, andOMS G&A increased by $0.7 million. Consolidated G&A expenses included non-cash amortization for stock-based compensation of $21.3 million and $12.0million in 2014 and 2013, respectively. As of December 31, 2014, we had 558 full-time employees as compared to 405 full-time employees as ofDecember 31, 2013.Gain on sale of properties. We recognized a gain on sale of properties of $187.0 million related to the Sanish Divestiture in the year ended December 31,2014. No gain or loss on sale of properties was recorded in the year ended December 31, 2013.Derivatives. As a result of entering into derivative contracts and the effect of the forward strip oil price changes, we incurred a $327.0 million net gain onderivative instruments, including net cash settlement receipts of $6.8 million, for the year ended December 31, 2014, and a $35.4 million net loss onderivative instruments, including net cash settlement payments of $8.1 million, for the year ended December 31, 2013. Cash settlements represent thecumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modifythe derivative instruments that were settled.Interest expense. Interest expense increased $51.2 million to $158.4 million for the year ended December 31, 2014 as compared to the year endedDecember 31, 2013. The increase was primarily due to the interest related to our senior unsecured notes issued in September 2013 at an interest rate of6.875% coupled with interest expense incurred on borrowings under our revolving credit facility during 2014. For the year ended December 31, 2014, theweighted average debt outstanding under our revolving credit facility was $272.3 million and the weighted average interest rate incurred on the outstandingborrowings was 1.8%. For the year ended December 31, 2013, the weighted average debt outstanding under our revolving credit facility was $143.0 millionand the weighted average interest rate incurred on the outstanding borrowings was 2.0%. We capitalized $8.8 million and $4.6 million of interest costs for theyears ended December 31, 2014 and 2013, respectively, which will be amortized over the life of the related assets.56Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIncome tax expense. Income tax expense for the years ended December 31, 2014 and 2013 was recorded at 37.8% and 37.2% of pre-tax net income,respectively, which closely approximates the statutory rate applicable to the U.S. and the blended state rate of the states in which we conduct business.Liquidity and capital resourcesOur primary sources of liquidity as of the date of this report have been proceeds from our senior unsecured notes, borrowings under our revolving creditfacility, proceeds from public equity offerings, cash flows from operations, the sale of non-core oil and gas properties and cash settlements of derivativecontracts. Our primary uses of capital have been for the acquisition and development of oil and natural gas properties. We continually monitor potentialcapital sources, including equity and debt financings and potential asset monetizations, in order to enhance liquidity and decrease leverage. Our futuresuccess in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.Our cash flows for the years ended December 31, 2015, 2014 and 2013 are presented below: Year ended December 31, 2015 2014 2013 (In thousands)Net cash provided by operating activities$359,815 $872,516 $697,856Net cash used in investing activities(479,148) (1,077,452) (2,445,076)Net cash provided by financing activities83,252 158,846 1,625,674Net change in cash$(36,081) $(46,090) $(121,546)Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well asfuture acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in oilprices on a portion of our production, thereby mitigating our exposure to oil price declines, but these transactions may also limit our cash flow in periods ofrising oil prices. Prices for oil have declined significantly since mid-2014, which has substantially decreased our cash flows provided by operating activities.The decline in operating cash flows caused by lower oil prices is partially offset by cash flows from our derivative contracts. We currently have derivativecontracts in place to cover approximately 70% of our estimated 2016 oil production at an average WTI of $51.70 per barrel. On February 2, 2016, wecompleted a public equity offering resulting in net proceeds of $182.9 million, after deducting underwriting discounts and commissions and estimatedoffering expenses, which we will use for general corporate purposes and to fund a portion of our 2016 capital expenditures. Our existing revolving creditfacility provides additional liquidity, with a current borrowing base and elected commitment amount of $1,150.0 million. The next redetermination of theborrowing base is scheduled for October 1, 2016. We believe we have adequate liquidity to fund planned 2016 capital expenditures and to meet our near-term future obligations. For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and QualitativeDisclosures about Market Risk.”Cash flows provided by operating activitiesNet cash provided by operating activities was $359.8 million, $872.5 million and $697.9 million for the years ended December 31, 2015, 2014 and 2013,respectively. The decrease in cash flows provided by operating activities for the year ended December 31, 2015 as compared to 2014 was primarily the resultof the 48% decrease in realized prices for oil and the 69% decrease in realized prices for natural gas coupled with decreases in well completion product salesto third parties, offset by our 11% increase in oil and natural gas production and increases in salt water pipeline transport, salt water disposal and fresh watersales. The increase in cash flows provided by operating activities for the year ended December 31, 2014 as compared to 2013 was primarily the result ofour 35% increase in oil and natural gas production coupled with increases in well completion activity, well completion product sales, tool rentals, salt waterpipeline transport, salt water disposal and fresh water sales, offset by lower realized oil sales prices year over year.Working capital. Our working capital fluctuates primarily as a result of changes in commodity pricing and production volumes, capital spending to fund ourexploratory and development initiatives and acquisitions and the impact of our outstanding derivative instruments. We had a working capital deficit of $5.3million at December 31, 2015, however, we believe we have adequate liquidity to meet our working capital requirements. As of December 31, 2015,including pro forma adjustments for our current borrowing base and the net proceeds from our February 2016 public equity offering, we had $1,199.4 millionof liquidity available. At December 31, 2014, we had a working capital deficit of $98.5 million.Cash flows used in investing activities57Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsWe had net cash flows used in investing activities of $479.1 million, $1,077.5 million and $2,445.1 million during the years ended December 31, 2015, 2014and 2013, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs and cash settlements of derivativecontracts. The decrease in cash used in investing activities for the year ended December 31, 2015 as compared to the year ended December 31, 2014 wasprimarily due to a 61% decrease in our capital expenditures year over year as a result of lower commodity prices. Net cash used in investing activities duringthe year ended December 31, 2015 was primarily attributable to $819.8 million in capital expenditures, which were primarily for the development of ourproperties, including OMS pipelines, salt water disposal wells and natural gas processing plant construction, partially offset by $370.4 million for derivativesettlements received as a result of lower crude oil prices. Net cash used in investing activities during the year ended December 31, 2014 was primarilyattributable to $1,354.3 million in capital expenditures for the development of our properties, including OMS pipelines and salt water disposal wells and theaddition of a second fracturing fleet for OWS, partially offset by $324.9 million in proceeds from the Sanish Divestiture. Net cash used in investing activitiesduring the year ended December 31, 2013 was primarily attributable to $1,560.1 million for the 2013 Acquisitions coupled with capital expenditures of$893.5 million for the development of our properties.Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. Our capital expenditures for theyears ended December 31, 2015, 2014 and 2013 are summarized in the following table: Year ended December 31, 2015 2014 2013 (In thousands)Capital expenditures E&P$465,698 $1,436,922 $2,461,185OMS96,947 68,939 18,955OWS21,711 37,292 15,217Other capital expenditures(1)25,643 29,440 10,941Total capital expenditures(2)$609,999 $1,572,593$2,506,298__________________ (1)Other capital expenditures include such items as administrative capital and capitalized interest.(2)Capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisition of oil andgas properties shown in the statement of cash flows in our consolidated financial statements because amounts reflected in the table include changes inaccrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows arepresented on a cash basis.In 2015, we spent $610.0 million on capital expenditures, which represented a 61% decrease as compared to the $1,572.6 million spent during 2014. Thisdecrease was due to reduced drilling and completion activity as a result of lower commodity prices in 2015 coupled with lower well costs as a result of bothimproved operational efficiency and lower service costs, partially offset by higher capital expenditures for OMS, primarily related to the natural gasprocessing plant we are constructing in the Wild Basin area of our core acreage in North Dakota.During 2015, we participated in 121 gross wells (64.3 net) that were completed and placed on production, and, as operator, we completed and placed onproduction 80 gross (62.4 net) of these wells. In addition, as of December 31, 2015, we had 85 gross operated wells awaiting completion in the Bakken andThree Forks formations. Our land leasing and acquisition activity is focused in and around our existing core consolidated land positions.We have decreased our planned 2016 capital expenditures as compared to 2015 as a result of current lower oil prices. We anticipate investing $400 million in2016 as follows: (In thousands)Drilling and completion$200,000OMS, including Wild Basin infrastructure140,000Other(1)60,000Total capital expenditures$400,000__________________ (1)Other capital expenditures include approximately $18 million for capitalized interest.58Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsWhile we have budgeted $400 million for total capital expenditures in 2016, the ultimate amount of capital we will expend may fluctuate materially basedon market conditions and the success of our drilling and operations results as the year progresses. Additionally, if we acquire additional acreage, our capitalexpenditures may be higher than budgeted. We believe that cash on hand, including the proceeds from our equity offering in February 2016, cash flows fromoperating activities, proceeds from cash settlements under our derivative contracts and availability under our revolving credit facility should be sufficient tofund our 2016 capital expenditure budget. However, because the operated wells funded by our 2016 drilling plan represent only a small percentage of ourpotential drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of potential drillinglocations should we elect to do so.Our capital budget may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionaryand within our control. If oil prices remain low for an extended period of time or continue to decline, we could defer a significant portion of our budgetedcapital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cashflows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs,industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations,internally generated cash flows and other factors both within and outside our control. We actively review acquisition opportunities on an ongoing basis. Ourability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on termsacceptable to us or at all.Cash flows provided by financing activitiesNet cash provided by financing activities was $83.3 million, $158.8 million and $1,625.7 million for the years ended December 31, 2015, 2014 and 2013,respectively. For the year ended December 31, 2015, cash sourced through financing activities was provided by net proceeds from the issuance of ourcommon stock, partially offset by net repayments on our revolving credit facility. For the year ended December 31, 2014, cash sourced through financingactivities was provided by borrowings under our revolving credit facility. For the year ended December 31, 2013, cash sourced through financing activitieswas primarily provided by the issuance of our senior unsecured notes, borrowings under our revolving credit facility and net proceeds from the issuance ofour common stock.Sale of common stock. On March 9, 2015, we completed a public offering of 36,800,000 shares of our common stock at an offering price of $12.80 per share.We used the net proceeds from the offering of $462.8 million, after deducting underwriting discounts and commissions and estimated offering expenses, torepay outstanding indebtedness under our revolving credit facility and for general corporate purposes.On February 2, 2016, we completed a public offering of 39,100,000 shares of our common stock at a purchase price of $4.685 per share. Net proceeds from theoffering were $182.9 million, after deducting underwriting discounts and commissions and estimated offering expenses, which we intend to use for generalcorporate purposes and to fund a portion of our 2016 capital expenditures.Senior unsecured notes. As of December 31, 2015, our long-term debt includes outstanding senior unsecured note obligations of $2,200.0 million, including$400.0 million of 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”), $400.0 million of 6.5% senior unsecured notes due November 1,2021 (the “2021 Notes”), $1,000.0 million of 6.875% senior unsecured notes due March 15, 2022 (the “2022 Notes”) and $400.0 million of 6.875% seniorunsecured notes due January 15, 2023 (the “2023 Notes,” and together with the 2019 Notes, the 2021 Notes and the 2022 Notes, the “Notes”). Interest on theNotes is payable semi-annually in arrears.Prior to certain dates, we have certain options to redeem up to 35% of the Notes at a certain redemption price based on a percentage of the principal amount,plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days ofcompleting such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to certaindates, the Company has the option to redeem some or all of the Notes for cash at certain redemption prices equal to a certain percentage of their principalamount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. We may from time to time seek to retire or purchaseour outstanding Notes through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiatedtransactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractualrestrictions and other factors. The amounts involved may be material.The Notes are guaranteed on a senior unsecured basis by our material subsidiaries (the “Guarantors”). The indentures governing the Notes restrict our abilityand the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem orrepurchase equity interests; (iii) make certain investments;59Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents(iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenantsare subject to a number of important exceptions and qualifications. If at any time when our Notes are rated investment grade by both Moody’s InvestorsService, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenantswill terminate and we will cease to be subject to such covenants.On October 26, 2015, we, along with our Guarantors, and U.S. Bank National Association, as trustee, entered into supplemental indentures respectingamendments (the “Amendments”) to the indentures governing the 2019 Notes, the 2021 Notes and the 2023 Notes (collectively, the “Consent Notes”)following our receipt of requisite consents of the holders of the Consent Notes pursuant to consent solicitations that commenced on October 6, 2015. TheAmendments amend the basket for secured credit facilities indebtedness in each of the indentures by (i) adding a provision that allows us to incur securedcredit facilities indebtedness up to the amount of our borrowing base at the time of the incurrence, but not to exceed $1,525.0 million and (ii) adding,deleting or revising several related definitions in the indentures, which changes generally restrict our ability to incur second-lien indebtedness.Senior secured revolving line of credit. We have a revolving credit facility (the “Second Amended Credit Facility”) with an overall senior secured line ofcredit of $2,500.0 million as of December 31, 2015. The Second Amended Credit Facility is restricted to the borrowing base, which is reserve-based andsubject to semi-annual redeterminations on April 1 and October 1 of each year. On April 13, 2015, we entered into our third amendment to the SecondAmended Credit Facility (the “Third Amendment”), which extended the maturity date of the Second Amended Credit Facility to April 13, 2020, providedthat the 2019 Notes are retired or refinanced 90 days prior to the maturity of the 2019 Notes. In connection with the Third Amendment, the lenders under theSecond Amended Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2015,resulting in a borrowing base decrease from $2,000.0 million to $1,700.0 million, and at that time, we increased the Lenders’ aggregate elected commitmentfrom $1,500.0 million to $1,525.0 million. On October 6, 2015, the Lenders completed their regular semi-annual redetermination of the borrowing basescheduled for October 1, 2015, resulting in a borrowing base decrease from $1,700.0 million to $1,525.0 million, which was equal to the Lenders’ aggregateelected commitment. On February 23, 2016, the Lenders completed their regular semi-annual redetermination of the borrowing base scheduled for April 1,2016, resulting in a decrease in the borrowing base and aggregate elected commitment from $1,525.0 million to $1,150.0 million. The next redeterminationof the borrowing base is scheduled for October 1, 2016.As of December 31, 2015, we had $138.0 million of borrowings at a weighted average interest rate of 1.9% and $5.2 million of outstanding letters of creditissued under the Second Amended Credit Facility. As of December 31, 2015, including pro forma adjustments for the current borrowing base and the netproceeds from our public equity offering in February 2016, we had unused borrowing base committed capacity of $1,144.8 million. As of December 31, 2014,we had $500.0 million of borrowings at a weighted average interest rate of 1.9% and $5.2 million of outstanding letters of credit issued under the SecondAmended Credit Facility, resulting in an unused borrowing base committed capacity of $994.8 million.The Second Amended Credit Facility contains covenants that include, among others:•a prohibition against incurring debt, subject to permitted exceptions;•a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;•a prohibition against making investments, loans and advances, subject to permitted exceptions;•restrictions on creating liens and leases on our assets and our subsidiaries, subject to permitted exceptions;•restrictions on merging and selling assets outside the ordinary course of business;•restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;•a provision limiting oil and natural gas derivative financial instruments;•a requirement that we maintain a ratio of consolidated EBITDAX (as defined in the Second Amended Credit Facility) to consolidated InterestExpense (as defined in the Second Amended Credit Facility) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter;and•a requirement that we maintain a Current Ratio (as defined in the Second Amended Credit Facility) of consolidated current assets (includingunused borrowing base committed capacity and with exclusions as described in the Second Amended Credit Facility) to consolidated currentliabilities (with exclusions as described in the Second Amended Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.The Second Amended Credit Facility contains customary events of default. If an event of default occurs and is continuing, the lenders may declare allamounts outstanding under the Second Amended Credit Facility to be immediately due and payable. We60Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentswere in compliance with the financial covenants of the Second Amended Credit Facility as of December 31, 2015 and 2014. As of December 31, 2015, ourconsolidated EBITDAX was $820.2 million and our consolidated Interest Expense was $161.0 million, resulting in a ratio of 5.1 as compared to a minimumrequired ratio of 2.5. In addition, as of December 31, 2015, our consolidated current assets and consolidated current liabilities (as described above) were$1,607.4 million and $370.6 million, resulting in a Current Ratio of 4.3 as compared to a minimum required ratio of 1.0. Given the extended decline incommodity prices, we continue to closely monitor our financial covenants and do not anticipate a covenant violation in the next twelve months.Obligations and commitmentsWe have the following contractual obligations and commitments as of December 31, 2015: Payments due by periodContractual obligationsTotal Within 1year 1-3 years 3-5 years More than5 years (In thousands)Senior unsecured notes(1)$2,200,000 $— $— $400,000 $1,800,000Interest payments on senior unsecured notes(1)910,625 151,250 302,500 259,000 197,875Borrowings under revolving credit facility(1)138,000 — — 138,000 —Interest payments on borrowings under revolving creditfacility(1)185 185 — — —Asset retirement obligations(2)35,812 32 1,241 317 34,222Operating leases(3)26,548 7,737 10,090 8,721 —Drilling rig commitments(3)5,686 5,686 — — —Volume commitment agreements(3)448,406 4,117 98,619 106,037 239,633Purchase agreements(3)42,352 1,560 16,942 16,700 7,150Total contractual cash obligations$3,807,614 $170,567 $429,392 $928,775 $2,278,880__________________ (1)See Note 9 to our audited consolidated financial statements for a description of our senior unsecured notes, revolving credit facility and relatedinterest payments. As of December 31, 2015, we had $138.0 million of borrowings and $5.2 million of outstanding letters of credit issued under ourSecond Amended Credit Facility.(2)Amounts represent our estimate of future asset retirement obligations (“ARO”). Because these costs typically extend many years into the future,estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors,including the rate of inflation, changing technology and the political and regulatory environment. See Note 10 to our audited consolidated financialstatements.(3)See Note 17 to our audited consolidated financial statements for a description of our operating leases, drilling rig commitments, volume commitmentagreements and purchase agreements.Critical accounting policies and estimatesThe discussion and analysis of our financial condition and results of operations are based upon our audited consolidated financial statements, which havebeen prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affectthe reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policiesinvolve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported underdifferent conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates onhistorical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for makingjudgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimatesand assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies,estimates and judgments used in preparation of our consolidated financial statements below. See Note 2 to our audited consolidated financial statements for adiscussion of additional accounting policies and estimates made by management.Method of accounting for oil and natural gas propertiesOil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisitioncosts and costs of exploratory and development wells are capitalized when incurred, pending61Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsdetermination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged toexpense. The costs of development wells are capitalized whether productive or nonproductive.The provision for DD&A of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. All capitalized wellcosts and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and totalproved reserves, respectively. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. Thecalculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which arenet of estimated salvage values.Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds, toaccumulated DD&A unless doing so significantly affects the unit-of-production amortization rate for an entire field, in which case a gain or loss is recognizedcurrently.Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Majorbetterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonmentcosts for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over theremaining life of the related proved developed reserves.Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leasesexpire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated lease acquisition costs. The expensing ofthe lease acquisition costs is recorded as impairment of oil and gas properties in our Consolidated Statement of Operations. Lease acquisition costs related tosuccessful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and thenet carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceedsexceed the entire cost of the property.Oil and natural gas reserve quantities and standardized measure of future net revenueOur independent reserve engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the SECrules allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. TheSEC’s rules define proved reserves as the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonablecertainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods andgovernment regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or theoperator must be reasonably certain that it will commence the project within a reasonable time. Our independent reserve engineers and technical staff mustmake a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually andconsider recent production levels and other technical information about each field. Oil and natural gas reserve engineering is a subjective process ofestimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of thequality of available data and of engineering and geological interpretation and judgment.Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoirperformance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors.Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amountsor timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result inimpairment of assets that may be material.Revenue recognitionOil and gas revenue from our interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumedthe risks and rewards of ownership, and collectability is reasonably assured. Substantially all of our production is sold to purchasers under short-term (lessthan twelve month) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions.These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to62Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsreflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it isproduced at various locations. As a result, we maintain a minimum amount of product inventory in storage.Well services revenue is recognized when well completion or other well services have been performed or when well completion products have beendelivered. OWS provides well services and sells well completion products primarily to OPNA. Midstream revenues consist primarily of revenues from saltwater pipeline transport, salt water disposal and fresh water sales for OPNA’s operated wells. Prior to the formation of OMS in 2013, the salt water disposalsystems were owned by OPNA, and the related income was included as a reduction to lease operating expenses. The revenues related to OPNA’s workinginterests are eliminated in consolidation, and only the revenues related to other working interest owners in OPNA’s wells are included in our ConsolidatedStatement of Operations.Impairment of proved propertiesWe review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of theircarrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare suchundiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carryingamount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. Thefactors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties,the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, futureproduction estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated withrealizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges forproved oil and natural gas properties will be recorded. Please see “Overview” for a discussion of potential future impairment charges.Impairment of unproved propertiesThe assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodicallyfor impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage.We recognize impairment expense for unproved properties at the time when the lease term has expired or sooner based on management’s periodicassessments. We consider the following factors in our assessment of the impairment of unproved properties:•the remaining amount of unexpired term under our leases;•our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may beclose to expiration;•our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;•our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and•our evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forksformations by us or by other operators in areas adjacent to or near our unproved properties.Business combinationsWe account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired andliabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations areexpensed as incurred.We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it isdetermined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved andunproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a singlediscounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and amarket-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to63Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsadditional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of oil and natural gas properties withinthe same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for suchproperties.Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of netassets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differencesbetween the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis ofassets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additionalinformation becomes known.Asset retirement obligationsWe record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding costcapitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled oracquired. The ARO represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, inaccordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are amortized on the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in our Consolidated Statement ofOperations.We determine the ARO by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requiresmanagement to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in thefair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing ofsettlement and changes in the legal, regulatory, environmental and political environments. If actual results are not consistent with our assumptions andestimates or our assumptions and estimates change due to new information, we may be exposed to future revisions, which could result in an increase to theexisting ARO liability and could ultimately result in a higher potential impact on our operations and cash flows for settlement charges. To the extent futurerevisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.DerivativesWe record all derivative instruments on the Consolidated Balance Sheet as either assets or liabilities measured at their estimated fair value. The significantinputs used to estimate fair value are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. Derivative assets andliabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. Wehave not designated any derivative instruments as hedges for accounting purposes, and we do not enter into such instruments for speculative tradingpurposes. Gains and losses from valuation changes in commodity derivative instruments are reported under other income (expense) in our ConsolidatedStatement of Operations. Our cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a paymentto or from the counterparty. These cash settlements represent the cumulative gains and losses on our derivative instruments and do not include a recovery ofcosts that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in ourConsolidated Statement of Cash Flows.Stock-based compensationRestricted stock awards. We recognize compensation expense for all restricted stock awards made to employees and directors. Stock-based compensationexpense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite serviceperiod, which is generally the vesting period. The fair value of restricted stock grants is based on the value of our common stock on the date of grant.Assumptions regarding forfeiture rates are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized. Stock-based compensation expense recorded for restricted stock awards is included in general and administrativeexpenses on our Consolidated Statement of Operations.Performance share units. We recognize compensation expense for our performance share units (“PSUs”) granted to our officers. Stock-based compensationexpense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the performance period,which is generally the vesting period. The fair value of the PSUs is based on the calculation derived from a Monte Carlo simulation model. The Monte Carlosimulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probable assessment (see Note 1264Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsto our audited consolidated financial statements for a description of the inputs used in this model). Stock-based compensation expense recorded for PSUs isincluded in general and administrative expenses on our Consolidated Statement of Operations.Income taxesOur provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes underGAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between thebook carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply totaxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assetsand liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reducedeferred tax assets if it is more likely than not that the related tax benefits will not be realized.We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, thereare many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences coulddiffer significantly from our estimates, which could impact our financial position, results of operations and cash flows.We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold andmeasurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxesrequires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than notsustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is thelargest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.Recent accounting pronouncementsRevenue recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue fromContracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-stepmodel to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASBissued Accounting Standards Update No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenuestandard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reportingperiod. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.Going concern. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability toContinue as a Going Concern (“ASU 2014-15”). ASU 2014-15 codifies in GAAP management’s responsibility to evaluate whether there is substantial doubtabout an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual reporting periodending after December 15, 2016 and for annual periods and interim periods thereafter. The adoption of this guidance will not impact our financial position,cash flows or results of operations, but could result in additional disclosures.Extraordinary items. In January 2015, the FASB issued Accounting Standards Update No. 2015-01, Simplifying Income Statement Presentation byEliminating the Concept of Extraordinary Items (“ASU 2015-01”). ASU 2015-01 removes the concept of extraordinary items from GAAP. Under existingguidance, an entity is required to separately disclose extraordinary items, net of tax, in the income statement after income from continuing operations if anevent or transaction is of an unusual nature and occurs infrequently. This separate, net-of-tax presentation will no longer be allowed. ASU 2015-01 iseffective for fiscal years beginning after December 15, 2015, including interim periods within those years. We do not expect the adoption of this guidance tohave a material impact on our financial position, cash flows or results of operations.Inventory. In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”). ASU2015-11 changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, firstout (FIFO) or average cost methods. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within thoseyears. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.Business combinations. In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”), which eliminates the requirement for an acquirer in a business combination to restate prior period financial statementsfor measurement period adjustments. ASU 2015-16 requires that the cumulative impact of measurement period adjustments on current and prior periods berecognized in the reporting period in which the adjustment amount is determined. ASU 2015-16 is effective for fiscal years beginning after December 15,65Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents2015, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our financial position,cash flows and results of operations.Financial instruments. In January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets andFinancial Liabilities (“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair valuerecognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements forfinancial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective forfiscal years beginning after December 15, 2017, including interim periods within those years. We are currently evaluating the effect that adopting thisguidance will have on our financial position, cash flows and results of operations.InflationInflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years endedDecember 31, 2015, 2014 and 2013. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy,and in the past, we have tended to experience inflationary pressure on the cost of midstream and oilfield services and equipment as increasing oil and naturalgas prices increased drilling activity in our areas of operations. In 2015, we experienced service cost reductions as a result of lower oil prices and decreaseddrilling activity in the Williston Basin.Off-balance sheet arrangementsCurrently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitmentagreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP. See“Obligations and commitments” above and Note 17 to our audited consolidated financial statements for a description of our commitments and contingencies.Non-GAAP Financial MeasuresAdjusted EBITDA and Adjusted Net Income are supplemental non-GAAP financial measures that are used by management and external users of ourconsolidated financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP measures should not be considered inisolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measures prepared under GAAP. BecauseAdjusted EBITDA and Adjusted Net Income exclude some but not all items that affect net income and may vary among companies, the amounts presentedmay not be comparable to similar metrics of other companies.Adjusted EBITDAWe define Adjusted EBITDA as earnings before interest expense, income taxes, DD&A, exploration expenses and other similar non-cash or non-recurringcharges. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. Management believes that the presentation of AdjustedEBITDA provides useful additional information to investors and analysts for assessing our results of operations and our ability to incur and service debt andto fund capital expenditures.The following table presents reconciliations of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDA for the periods presented:66Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents Year Ended December 31, 2015 2014 2013 (In thousands)Net income (loss)$(40,248) $506,877 $227,959Gain on sale of properties— (186,999) —Net (gain) loss on derivative instruments(210,376) (327,011) 35,432Derivative settlements(1)370,410 6,774 (8,133)Interest expense, net of capitalized interest149,648 158,390 107,165Depreciation, depletion and amortization485,322 412,334 307,055Impairment of oil and gas properties46,109 47,238 1,168Exploration expenses2,369 3,064 2,260Rig termination3,895 — —Stock-based compensation expenses25,272 21,302 11,982Income tax (benefit) expense(16,123) 307,591 135,058Other non-cash adjustments3,956 3,284 1,910Adjusted EBITDA$820,234 $952,844 $821,856 Net cash provided by operating activities$359,815 $872,516 $697,856Derivative settlements(1)370,410 6,774 (8,133)Interest expense, net of capitalized interest149,648 158,390 107,165Exploration expenses2,369 3,064 2,260Rig termination3,895 — —Deferred financing costs amortization and other(12,299) (11,028) (4,248)Current tax (benefit) expense(9) 134 475Changes in working capital(57,551) (80,290) 24,571Other non-cash adjustments3,956 3,284 1,910Adjusted EBITDA$820,234 $952,844 $821,856____________________(1)Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery ofcosts that were paid to acquire or modify the derivative instruments that were settled.The following tables present reconciliations of the GAAP financial measure of income (loss) before income taxes to the non-GAAP financial measure ofAdjusted EBITDA for our three reportable business segments on a gross basis for the periods presented:Exploration and Production Year Ended December 31, 2015 2014 2013 (In thousands)Income (loss) before income taxes$(118,970) $779,591 $331,781Gain on sale of properties— (186,999) —Net (gain) loss on derivative instruments(210,376) (327,011) 35,432Derivative settlements(1)370,410 6,774 (8,133)Interest expense, net of capitalized interest149,648 158,390 107,165Depreciation, depletion and amortization479,693 406,960 304,388Impairment of oil and gas properties46,109 47,238 1,168Exploration expenses2,369 3,064 2,260Rig termination3,895 — —Stock-based compensation expenses24,762 20,701 11,602Other non-cash adjustments3,719 2,314 1,371Adjusted EBITDA$751,259 $911,022 $787,034____________________67Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents(1)Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery ofcosts that were paid to acquire or modify the derivative instruments that were settled.Well Services Year Ended December 31, 2015 2014 2013 (In thousands)Income before income taxes$49,197 $70,953 $56,338Depreciation, depletion and amortization19,073 14,080 7,150Stock-based compensation expenses1,952 1,658 969Other non-cash adjustments237 970 539Adjusted EBITDA$70,459 $87,661 $64,996Midstream Services Year Ended December 31, 2015 2014 2013(1) (In thousands)Income before income taxes$59,867 $22,730 $17,509Depreciation, depletion and amortization5,764 3,744 2,780Stock-based compensation expenses692 — —Adjusted EBITDA$66,323 $26,474 $20,289____________________(1)Our midstream business segment (OMS) was not formed until the first quarter of 2013.Adjusted Net Income and Adjusted Diluted Earnings Per ShareWe define Adjusted Net Income as net income (loss) after adjusting first for (1) the impact of certain non-cash and non-recurring items, including non-cashchanges in the fair value of derivative instruments, impairment of oil and gas properties and other similar non-cash and non-recurring charges, and then(2) the non-cash and non-recurring items’ impact on taxes based on our effective tax rate applicable to those items in the same period. Adjusted Net Income isnot a measure of net income (loss) as determined by GAAP. We define Adjusted Diluted Earnings Per Share as Adjusted Net Income divided by dilutedweighted average shares outstanding. Management believes that the presentation of Adjusted Net Income and Adjusted Diluted Earnings Per Share providesuseful additional information to investors and analysts for evaluating our operational trends and performance.The following table presents reconciliations of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted Net Incomeand the GAAP financial measure of diluted earnings (loss) per share to the non-GAAP financial measure of Adjusted Diluted Earnings Per Share for theperiods presented:68Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents Year Ended December 31, 2015 2014 2013 (In thousands, except per share data)Net income (loss)$(40,248) $506,877 $227,959Gain on sale of properties— (186,999) —Net (gain) loss on derivative instruments(210,376) (327,011) 35,432Derivative settlements(1)370,410 6,774 (8,133)Impairment of oil and gas properties46,109 47,238 1,168Rig termination3,895 — —Other non-cash adjustments3,956 3,284 1,910Tax impact(2)(79,991) 172,482 (11,302)Adjusted Net Income$93,755 $222,645 $247,034 Diluted earnings per share$(0.31) $5.05 $2.44Gain on sale of properties— (1.86) —Net (gain) loss on derivative instruments(1.62) (3.26) 0.38Derivative settlements(1)2.85 0.07 (0.09)Impairment of oil and gas properties0.35 0.47 0.01Rig termination0.03 — —Other non-cash adjustments0.03 0.03 0.02Tax impact(2)(0.61) 1.72 (0.12)Adjusted Diluted Earnings Per Share$0.72 $2.22 $2.64 Diluted weighted average shares outstanding130,186 100,365 93,411 Effective tax rate applicable to adjustment items37.4% 37.8% 37.2%____________________(1)Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery ofcosts that were paid to acquire or modify the derivative instruments that were settled.(2)The tax impact is computed utilizing our effective tax rate applicable to the adjustments for certain non-cash and non-recurring items.Item 7A. Quantitative and Qualitative Disclosures about Market RiskWe are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risksthrough a program of risk management, including the use of derivative instruments.Commodity price exposure risk. We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes in supply and demand andother factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enterinto derivative instruments in the future to cover a significant portion of our future production. We currently have derivative contracts in place to coverapproximately 70% of our expected 2016 oil production.We utilize derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2015, we utilized two-way collar options andswaps to reduce the volatility of oil prices on a significant portion of our future expected oil production. A two-way collar is a combination of options: a soldcall and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive forthe volumes under contract. A swap is a sold call and a purchased put established at the same price (both ceiling and floor).We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amountsrecognized on the balance sheet. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a netbasis, as all counterparty contracts provide for net settlement.The following is a summary of our derivative contracts as of December 31, 2015:69Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSettlementPeriod DerivativeInstrument Total NotionalAmount of Oil Weighted Average Prices Fair ValueAsset(Liability) Swap Floor Ceiling (Barrels) ($/Barrel) (In thousands)2016 Two-way collars 155,000 $86.00 $103.42 7,4642016 Swaps 9,452,000 $54.89 132,2332017 Swaps 2,049,000 $53.17 15,1092018 Swaps 124,000 $53.62 667 $155,473Interest rate risk. At December 31, 2015, we had (i) $400.0 million of senior unsecured notes at a fixed cash interest rate of 7.25% per annum, (ii) $400.0million of senior unsecured notes at a fixed cash interest rate of 6.5% per annum and (iii) $1,400.0 million of senior unsecured notes at a fixed cash interestrate of 6.875% per annum outstanding. At December 31, 2015, we also had $138.0 million of borrowings and $5.2 million of outstanding letters of creditissued under our Second Amended Credit Facility, which were subject to varying rates of interest based on (1) the total outstanding borrowings (includingthe value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a LIBOR loan or a domestic bank prime interest rateloan (defined in the Second Amended Credit Facility as an Alternate Based Rate or “ABR” loan). At December 31, 2015, the outstanding borrowings underour Second Amended Credit Facility bore interest at LIBOR plus a 1.5% margin. We do not currently, but may in the future, utilize interest rate derivatives toalter interest rate exposure in an attempt to reduce interest rate expense related to debt issued under our Second Amended Credit Facility. Interest ratederivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entitiesparticipate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells.We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of oursignificant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.While we do not require all of our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of oursignificant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of suchcounterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating, latest financialinformation and, in the case of a customer with which we have receivables, their historical payment record, the financial ability of the customer’s parentcompany to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. Several of oursignificant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In thesecircumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.As permitted under our investments policy, we may purchase commercial paper instruments from high credit quality counterparties. These counterparties mayinclude issuers in a variety of industries including the domestic and foreign financial sector. This risk is managed by our investment policy includingminimum credit ratings thresholds and maximum counterparty exposure values. Although we do not anticipate any of our commercial paper issuers failing topay us upon maturity, we take a risk in purchasing the commercial paper instruments available in the marketplace. If an issuer fails to repay us at maturityfrom commercial paper proceeds, it could take a significant amount of time to recover a portion of or all of the assets originally invested. Our commercialpaper balance was $36,000 at December 31, 2015.In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order tomitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. Most of thecounterparties on our derivative instruments currently in place are Lenders under our Second Amended Credit Facility with investment grade ratings. We arelikely to enter into any future derivative instruments with these or other Lenders under our Second Amended Credit Facility, which also carry investmentgrade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individualcontracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these nettingprovisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. Wehad a net derivative asset position of $155.5 million and no net derivative liability position at December 31, 2015.70Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsItem 8. Financial Statements and Supplementary DataIndex to Financial Statements Report of Independent Registered Public Accounting Firm72 Consolidated Balance Sheet at December 31, 2015 and December 31, 201473 Consolidated Statement of Operations for the Years Ended December 31, 2015, 2014 and 201374 Consolidated Statement of Changes in Stockholders’ Equity for the Years Ended December 31, 2015, 2014 and 201375 Consolidated Statement of Cash Flows for the Years Ended December 31, 2015, 2014 and 201376 Notes to Consolidated Financial Statements7771Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsReport of Independent Registered Public Accounting FirmTo the Board of Directors and Stockholders of Oasis Petroleum Inc.:In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in stockholders’ equity andof cash flows present fairly, in all material respects, the financial position of Oasis Petroleum Inc. and its subsidiaries (the “Company”) at December 31, 2015and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity withaccounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effectiveinternal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control—Integrated Framework (2013) issued bythe Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements,for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting,included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on thesefinancial statements and on the Company’s internal control over financial reporting based on our audits. We conducted our audits in accordance with thestandards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtainreasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reportingwas maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overallfinancial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financialreporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on theassessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits providea reasonable basis for our opinions.A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal controlover financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are beingmade only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate./s/PricewaterhouseCoopers LLPHouston, TexasFebruary 25, 201672Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOasis Petroleum Inc.Consolidated Balance Sheet December 31, 2015 2014 (In thousands, except share data)ASSETS Current assets Cash and cash equivalents$9,730 $45,811Accounts receivable — oil and gas revenues96,495 130,934Accounts receivable — joint interest and other100,914 175,537Inventory11,072 21,354Prepaid expenses7,328 14,273Derivative instruments139,697 302,159Other current assets50 6,539Total current assets365,286 696,607Property, plant and equipment Oil and gas properties (successful efforts method)6,284,401 5,966,140Other property and equipment443,265 313,439Less: accumulated depreciation, depletion, amortization and impairment(1,509,424) (1,092,793)Total property, plant and equipment, net5,218,242 5,186,786Assets held for sale26,728 —Derivative instruments15,776 13,348Other assets23,343 12,335Total assets$5,649,375 $5,909,076LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable$9,983 $20,958Revenues and production taxes payable132,356 209,890Accrued liabilities167,669 410,379Accrued interest payable49,413 49,786Deferred income taxes— 97,499Advances from joint interest partners4,647 6,616Other current liabilities6,500 —Total current liabilities370,568 795,128Long-term debt2,302,584 2,670,664Deferred income taxes608,155 526,770Asset retirement obligations35,338 42,097Liabilities held for sale10,228 —Other liabilities3,160 2,116Total liabilities3,330,033 4,036,775Commitments and contingencies (Note 17) Stockholders’ equity Common stock, $0.01 par value: 300,000,000 shares authorized; 139,583,990 shares issued and 139,076,064shares outstanding at December 31, 2015 and 101,627,296 shares issued and 101,341,619 shares outstandingat December 31, 20141,376 1,001Treasury stock, at cost: 507,926 shares and 285,677 shares at December 31, 2015 and 2014, respectively(13,620) (10,671)Additional paid-in-capital1,497,065 1,007,202Retained earnings834,521 874,769Total stockholders’ equity2,319,342 1,872,301Total liabilities and stockholders’ equity$5,649,375 $5,909,076The accompanying notes are an integral part of these consolidated financial statements.73Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOasis Petroleum Inc.Consolidated Statement of Operations Year Ended December 31, 2015 2014 2013 (In thousands, except per share data)Revenues Oil and gas revenues$721,672 $1,304,004 $1,084,412Well services and midstream revenues68,063 86,224 57,587Total revenues789,735 1,390,228 1,141,999Operating expenses Lease operating expenses144,481 169,600 94,634Well services and midstream operating expenses28,031 50,252 30,713Marketing, transportation and gathering expenses31,610 29,133 25,924Production taxes69,584 127,648 100,537Depreciation, depletion and amortization485,322 412,334 307,055Exploration expenses2,369 3,064 2,260Rig termination3,895 — —Impairment of oil and gas properties46,109 47,238 1,168General and administrative expenses92,498 92,306 75,310Total operating expenses903,899 931,575 637,601Gain on sale of properties— 186,999 —Operating income (loss)(114,164) 645,652 504,398Other income (expense) Net gain (loss) on derivative instruments210,376 327,011 (35,432)Interest expense, net of capitalized interest(149,648) (158,390) (107,165)Other income (expense)(2,935) 195 1,216Total other income (expense)57,793 168,816 (141,381)Income (loss) before income taxes(56,371) 814,468 363,017Income tax benefit (expense)16,123 (307,591) (135,058)Net income (loss)$(40,248) $506,877 $227,959Earnings (loss) per share: Basic (Note 14)$(0.31) $5.09 $2.45Diluted (Note 14)(0.31) 5.05 2.44Weighted average shares outstanding: Basic (Note 14)130,186 99,677 92,867Diluted (Note 14)130,186 100,365 93,411 The accompanying notes are an integral part of these consolidated financial statements.74Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOasis Petroleum Inc.Consolidated Statement of Changes in Stockholders’ Equity Common Stock Treasury Stock Additional Paid-in-Capital RetainedEarnings(Deficit) TotalStockholders’Equity Shares Amount Shares Amount (In thousands)Balance as of December 31, 201293,303 $925 129 $(3,796) $657,943 $139,933 $795,005Issuance of common stock7,000 70 — — 314,510 — 314,580Stock-based compensation434 — — — 12,571 — 12,571Vesting of restricted shares— 1 — — (1) — —Treasury stock – tax withholdings(38) — 38 (1,566) — — (1,566)Net income— — — — — 227,959 227,959Balance as of December 31, 2013100,699 996 167 (5,362) 985,023 367,892 1,348,549Fees (2013 issuance of common stock)— — — — (176) — (176)Stock-based compensation762 — — — 22,360 — 22,360Vesting of restricted shares— 5 — — (5) — —Treasury stock – tax withholdings(119) — 119 (5,309) — — (5,309)Net income— — — — — 506,877 506,877Balance as of December 31, 2014101,342 1,001 286 (10,671) 1,007,202 874,769 1,872,301Issuance of common stock36,800 368 — — 462,465 — 462,833Stock-based compensation1,156 — — — 27,405 — 27,405Vesting of restricted shares— 7 — — (7) — —Treasury stock – tax withholdings(222) — 222 (2,949) — — (2,949)Net loss— — — — — (40,248) (40,248)Balance as of December 31, 2015139,076 1,376 508 (13,620) 1,497,065 834,521 2,319,342The accompanying notes are an integral part of these consolidated financial statements.75Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOasis Petroleum Inc.Consolidated Statement of Cash Flows Year Ended December 31, 2015 2014 2013 (In thousands)Cash flows from operating activities: Net income (loss)$(40,248) $506,877 $227,959Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization485,322 412,334 307,055Gain on sale of properties— (186,999) —Impairment of oil and gas properties46,109 47,238 1,168Deferred income taxes(16,114) 307,457 134,583Derivative instruments(210,376) (327,011) 35,432Stock-based compensation expenses25,272 21,302 11,982Deferred financing costs amortization and other12,299 11,028 4,248Working capital and other changes: Change in accounts receivable108,461 16,702 (107,473)Change in inventory6,873 (3,776) (13,941)Change in prepaid expenses1,828 (3,199) (8,191)Change in other current assets6,489 (6,135) (56)Change in other assets(950) 114 (3,248)Change in accounts payable and accrued liabilities(71,617) 76,723 107,451Change in other current liabilities6,500 — —Change in other liabilities(33) (139) 887Net cash provided by operating activities359,815 872,516 697,856Cash flows from investing activities: Capital expenditures(819,847) (1,354,281) (893,524)Acquisition of oil and gas properties(28,817) (46,247) (1,560,072)Proceeds from sale of properties1,075 324,852 —Costs related to sale of properties— (2,337) —Derivative settlements370,410 6,774 (8,133)Redemptions of short-term investments— — 25,000Advances from joint interest partners(1,969) (6,213) (8,347)Net cash used in investing activities(479,148) (1,077,452) (2,445,076)Cash flows from financing activities: Proceeds from issuance of senior notes— — 1,000,000Proceeds from revolving credit facility630,000 620,000 600,000Principal payments on revolving credit facility(992,000) (455,570) (264,430)Deferred financing costs(14,632) (99) (22,910)Proceeds from sale of common stock462,833 — 314,580Purchases of treasury stock(2,949) (5,309) (1,566)Other— (176) —Net cash provided by financing activities83,252 158,846 1,625,674Decrease in cash and cash equivalents(36,081) (46,090) (121,546)Cash and cash equivalents: Beginning of period45,811 91,901 213,447End of period$9,730 $45,811 $91,901Supplemental cash flow information: Cash paid for interest, net of capitalized interest$145,333 $150,181 $85,596Cash paid for taxes— 5,329 750Cash received for income tax refunds5,548 — —Supplemental non-cash transactions: Change in accrued capital expenditures$(260,060) $169,710 $34,354Change in asset retirement obligations3,972 6,182 13,201The accompanying notes are an integral part of these consolidated financial statements.76Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOasis Petroleum Inc.Notes to Consolidated Financial Statements1. Organization and Operations of the CompanyOasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) was originally formed in 2007 and was incorporatedpursuant to the laws of the State of Delaware in 2010. The Company is an independent exploration and production company focused on the acquisition anddevelopment of unconventional oil and natural gas resources in the North Dakota and Montana regions of the Williston Basin. Oasis Petroleum NorthAmerica LLC (“OPNA”) conducts the Company’s exploration and production activities and owns its proved and unproved oil and natural gas properties. TheCompany also operates a well services business through Oasis Well Services LLC (“OWS”) and a midstream services business through Oasis MidstreamServices LLC (“OMS”), both of which are separate reportable business segments that are complementary to its primary development and productionactivities.2. Summary of Significant Accounting PoliciesBasis of PresentationThe accompanying consolidated financial statements of the Company include the accounts of Oasis and its wholly-owned subsidiaries. Allsignificant intercompany transactions have been eliminated in consolidation. These statements have been prepared in accordance with accounting principlesgenerally accepted in the United States of America (“GAAP”). Certain reclassifications of prior year balances have been made to conform such amounts tocurrent year classifications. These reclassifications have no impact on net income.Use of EstimatesPreparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates andassumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenuesand expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used inimpairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gasrevenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptionsregarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain fornumerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating undergroundaccumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of dataavailable and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production,results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may bematerial and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, andimpairment expense.Risks and UncertaintiesAs an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing andfuture prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developmentsand competition from other energy sources. The energy markets have historically been very volatile and there can be no assurance that oil and natural gasprices will not be subject to wide fluctuations in the future. Oil and natural gas prices declined significantly in the latter part of 2014 and continued todecline while experiencing high volatility in 2015. As a result of lower commodity prices, the Company significantly decreased its 2015 and 2016 capitalexpenditures as compared to 2014 and is currently concentrating its drilling activities in certain areas that are the most economic in the Williston Basin. Anextended period of low prices for oil and, to a lesser extent, natural gas could have a material adverse effect on the Company’s financial position, results ofoperations, cash flows and quantities of oil and natural gas reserves that may be economically produced.Cash EquivalentsThe Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost whichapproximates fair value due to the short-term maturity of these investments. The Company classifies all such investments with original maturity dates lessthan 90 days as cash equivalents.77Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAccounts ReceivableAccounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable forcollectability and establishes an allowance as necessary for individual customer balances. No allowance for doubtful accounts was recorded for the yearsended December 31, 2015 and 2014.InventoryEquipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operationsand well fracturing equipment. Crude oil inventory includes oil in tank and linefill. Inventory is stated at the lower of cost or market value with costdetermined on an average cost method. Inventory consists of the following: December 31, 2015 2014 (In thousands)Equipment and materials$4,920 $14,225Crude oil inventory6,152 7,129Total inventory$11,072 $21,354Joint Interest Partner AdvancesThe Company participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital intensive nature ofoil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments fromother working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against jointinterest billings for its share of drilling operations within 90 days from when the advance is paid. Advances to joint interest partners are included in othercurrent assets on the Company’s Consolidated Balance Sheet.Property, Plant and EquipmentProved Oil and Gas PropertiesOil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all propertyacquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found provedreserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells arecapitalized whether productive or nonproductive.The provision for DD&A of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. Allcapitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developedreserves and total proved reserves, respectively. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrelof oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs,which are net of estimated salvage values.Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds,to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate for an entire field, in which case a gain or loss isrecognized currently. In March 2014, the Company sold certain non-operated properties in and around its Sanish position for cash proceeds of $324.9million. The Company recognized a gain of $187.0 million from this divestiture (see Note 6 — Acquisitions and Divestitures). No gain or loss for the sale ofoil and natural gas properties was recorded for the years ended December 31, 2015 and 2013.Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred.Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement andabandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-productionbasis over the remaining life of the related proved developed reserves.78Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in therecoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gasproperties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amountis recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil andnatural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are notlimited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs usingestimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount ratescommensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3inputs, as further discussed in Note 3 — Fair Value Measurements. Due to lower expected future oil prices, the Company reviewed its proved oil and naturalgas properties as of December 31, 2015 and 2014. For the year ended December 31, 2015, the Company recorded an impairment loss of $9.4 million to adjustthe carrying value of its proved oil and natural gas properties held for sale to their estimated fair value. For the year ended December 31, 2014, the Companydetermined that the carrying value exceeded expected undiscounted cash flows for certain assets, and as a result, recorded an impairment loss of $40.0million to adjust the carrying amount of these assets to fair value. No impairment of proved oil and natural gas properties was recorded for the year endedDecember 31, 2013.Unproved Oil and Gas PropertiesUnproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized untilthe leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated leaseacquisition costs. The expensing of the lease acquisition costs is recorded as impairment of oil and gas properties in the Consolidated Statement ofOperations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms,drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties:•the remaining amount of unexpired term under its leases;•its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close toexpiration;•its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;•its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and•its evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations by theCompany or by other operators in areas adjacent to or near the Company’s unproved properties.As a result of expiring unproved property leases and periodic assessments of unproved properties, the Company recorded non-cash impairmentcharges of $36.6 million, $7.3 million and $1.2 million for the years ended December 31, 2015, 2014 and 2013, respectively.For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceedsreceived and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costsunless the proceeds exceed the entire cost of the property.Capitalized InterestThe Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplyingthe capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period.The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is eitherplaced into production or written off. The Company capitalized $18.6 million, $8.8 million and $4.6 million of interest costs for the years endedDecember 31, 2015, 2014 and 2013, respectively. These amounts are amortized over the life of the related assets.Other Property and Equipment79Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSalt water disposal facilities, pipelines, buildings, furniture, software, equipment and leasehold improvements are recorded at cost and aredepreciated on the straight-line method based on expected lives of the individual assets. The Company uses estimated lives of 30 years for salt water disposalfacilities and pipelines, 20 years for buildings, two to seven years for furniture, software and equipment and the remaining lease term for leaseholdimprovements. The calculation for the straight-line DD&A method for salt water disposal facilities takes into consideration estimated future dismantlement,restoration and abandonment costs, which are net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A areremoved from the Company’s Consolidated Balance Sheet with any gain or loss realized upon the sale or disposal included in the Company’s ConsolidatedStatement of Operations.Exploration ExpensesExploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, arecharged to expense as incurred.Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful.Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drillingis completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons butcannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals beforeproduction can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future orthe necessary approvals are actively being sought.Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented: December 31, 2015 2014 2013 (In thousands)Beginning of period$34,522 $123,215 $40,424Exploratory well cost additions (pending determination of proved reserves)51,995 336,344 346,814Exploratory well cost reclassifications (successful determination of proved reserves)(84,228) (425,037) (264,023)Exploratory well dry hole costs (unsuccessful in adding proved reserves)— — —End of period$2,289 $34,522 $123,215As of December 31, 2015, the Company had no exploratory well costs that were capitalized for a period of greater than one year after thecompletion of drilling.Business CombinationsThe Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts foridentifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated withbusiness combinations are expensed as incurred.The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-basedmeasurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fairvalues of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert futurecash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, futurecommodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additionalproject-specific risking factors. In addition, when appropriate, the Company reviews comparable purchases and sales of oil and natural gas properties withinthe same regions and uses that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for suchproperties.Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair valueof net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differencesbetween the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis ofassets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additionalinformation becomes known.80Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAssets Held for SaleThe Company occasionally markets non-core oil and gas properties. At the end of each reporting period, the Company evaluates the propertiesbeing marketed to determine whether any should be reclassified as held-for-sale. The held-for-sale criteria include: management commits to a plan to sell; theasset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within oneyear; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, theproperty is reclassified as held-for-sale on the Company’s Consolidated Balance Sheet and measured at the lower of their carrying amount or estimated fairvalue less costs to sell. DD&A expense is not recorded on assets to be divested once they are classified as held for sale.Deferred Financing CostsThe Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financingusing the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense inthe Company’s Consolidated Statement of Operations.In the fourth quarter of 2015, the Company adopted Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt IssuanceCosts (“ASU 2015-03”), which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associateddebt liability, consistent with the presentation of debt discount, but does not affect the recognition or measurement of debt issuance costs. In accordance withthe new guidance, deferred financing costs related to the Company’s senior unsecured notes, which had been included in other assets prior to the adoption ofASU 2015-03, are now included in long-term debt on the Company’s Consolidated Balance Sheet, resulting in decreases in both other assets and long-termdebt of $35.4 million as of December 31, 2015. ASU 2015-03 was applied on a retrospective basis, wherein the balance sheet of each individual periodpresented was adjusted to reflect the period-specific effects of applying the new guidance. As a result, the Company’s Consolidated Balance Sheet as ofDecember 31, 2014 included a deduction for deferred financing costs of $29.3 million in long-term debt, which had previously been presented in other assets.Deferred financing costs incurred in connection with the Company’s revolving credit facility are not in the scope of ASU 2015-03 and are presented in otherassets on the Company’s Consolidated Balance Sheet consistent with prior periods.Asset Retirement ObligationsIn accordance with the Financial Accounting Standard Board’s (“FASB”) authoritative guidance on asset retirement obligations (“ARO”), theCompany records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding costcapitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled oracquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productivelives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in the Company’s ConsolidatedStatement of Operations.The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future AROrequires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherentin the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing ofsettlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussedin Note 3 — Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, acorresponding adjustment is made to the related asset.Revenue RecognitionOil and gas revenue from the Company’s interests in producing wells is recognized when the product is delivered, at which time the customer hastaken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of the Company’s production is sold topurchasers under short-term (less than twelve months) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportationand other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, theserevenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, the Companysells the majority of its production soon after it is produced at various locations. As a result, the Company maintains a minimum amount of product inventoryin storage.Well services revenue is recognized when well completion or other well services have been performed or related products have been delivered.OWS provides well services and sells well completion products primarily to OPNA. Midstream81Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsrevenues consist primarily of revenues from salt water pipeline transport, salt water disposal and fresh water sales for OPNA’s operated wells. Prior to theformation of OMS in 2013, the salt water disposal systems were owned by OPNA, and the related income was included as a reduction to lease operatingexpenses. The revenues related to OPNA’s working interests are eliminated in consolidation, and only the revenues related to other working interest ownersin OPNA’s wells are included in the Company’s Consolidated Statement of Operations.Revenues and Production Taxes PayableThe Company calculates and pays taxes and royalties on oil and natural gas in accordance with the particular contractual provisions of the lease,license or concession agreements and the laws and regulations applicable to those agreements.Concentrations of Market and Credit RiskThe future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability ofa ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports,marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply ofoil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can bepredicted with certainty. The current global oversupply of crude oil has caused a sharp decline in oil prices since mid-2014, and an extended period of lowprices for oil could have a material adverse effect on the Company’s financial position, cash flows and results of operations.The Company operates in the exploration, development and production sector of the oil and gas industry. The Company’s receivables includeamounts due from purchasers of its oil and natural gas production and amounts due from joint interest partners for their respective portions of operatingexpenses and exploration and development costs. While certain of these customers and joint interest partners are affected by periodic downturns in theeconomy in general or in their specific segment of the oil or natural gas industry, including the current period of low commodity prices, the Companybelieves that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results ofoperations over the long-term. In addition, a portion of the Company’s trade receivables are collateralized.The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financialinstruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances andderivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federallyinsured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposureto any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business,letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.Risk ManagementThe Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2015, the Companyutilized two-way costless collar options and swaps to reduce the volatility of oil prices on a significant portion of the Company’s future expected oilproduction (see Note 4 — Derivative Instruments).The Company records all derivative instruments on the Consolidated Balance Sheet as either assets or liabilities measured at their estimated fairvalue. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contractsprovide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into suchinstruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income(expense) section of the Company’s Consolidated Statement of Operations. The Company’s cash flow is only impacted when the actual settlements under thederivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses onthe Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivativeinstruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows.Derivative financial instruments that hedge the price of oil are executed with major financial institutions that expose the Company to market andcredit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has derivatives in place with eightcounterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event ofnonperformance by the82Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentscounterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk ofnonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from its counterparties. TheCompany’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement andInternational Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, crossdefault provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than crosscollateralization with the properties securing the Company’s revolving credit facility (see Note 9 — Long-Term Debt). As of December 31, 2015, theCompany had limitations under its revolving credit facility, including a provision limiting the total amount of production that may be hedged by theCompany to the lesser of projected production or 110% of Current Production (as defined in the revolving credit facility) for the period from 1 to 12 months,100% of Current Production for the period from 13 to 24 months, 75% of Current Production for the period from 25 to 36 months, and 50% of CurrentProduction for the period from 37 to 60 months after the date of each derivative. As of December 31, 2015, the Company was in compliance with theselimitations.Environmental CostsEnvironmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate toan existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recordedon an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.Stock-Based CompensationRestricted Stock AwardsThe Company has granted restricted stock awards to employees and directors under its Amended and Restated 2010 Long Term Incentive Plan,the majority of which vest over a three-year period. The fair value of restricted stock grants is based on the value of the Company’s common stock on the dateof grant. Compensation expense is recognized ratably over the requisite service period. The Company assumed annual forfeiture rates by employee groupranging from 0% to 16.9% based on the Company’s forfeiture history for this type of award. Stock-based compensation expense recorded for restricted stockawards is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.Performance Share UnitsThe Company recognizes compensation expense for its performance share units (“PSUs”) granted to its officers under its Amended and Restated2010 Long Term Incentive Plan. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized asexpense on a straight-line basis over the performance period, which is generally the vesting period. The fair value of the PSUs is based on the calculationderived from a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeatednumerous times to achieve a probable assessment (see Note 12 — Stock-Based Compensation for a description of the inputs used in this model). TheCompany assumed annual forfeiture rates by employee group ranging from 2.4% to 4.9% based on the Company’s forfeiture history for the employee groupsreceiving PSUs. Stock-based compensation expense recorded for PSUs is included in general and administrative expenses on the Company’s ConsolidatedStatement of Operations.Associated Excess Tax BenefitsAny excess tax benefit arising from the Company’s stock-based compensation plan is recognized as a credit to additional paid-in-capital whenrealized and is calculated as the amount by which the tax benefit related to the tax deduction received exceeds the deferred tax asset associated with therecorded stock-based compensation expense. As of December 31, 2015, the excess federal tax deduction related to stock-based compensation was $9.6million and the excess state tax deduction related to stock-based compensation was $7.6 million. Since the Company has been in and continues to be in a netoperating loss position for tax purposes, none of the excess tax deduction is reflected in additional paid-in-capital. Pursuant to GAAP, the Company’sdeferred tax asset related to net operating loss carryforward is net of the unrealized tax benefit from stock-based compensation.Treasury StockTreasury stock shares represent shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees uponthe vesting of restricted stock awards. The Company includes the withheld shares as83Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentstreasury stock on its Consolidated Balance Sheet and separately pays the payroll tax obligation. These retained shares are not part of a publicly announcedprogram to repurchase shares of the Company’s common stock and are accounted for at cost. The Company does not have a publicly announced program torepurchase shares of its common stock.Income TaxesThe Company’s provision for taxes includes both federal and state taxes. The Company records its federal income taxes in accordance withaccounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences oftemporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured usingenacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered orsettled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Avaluation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinarycourse of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future taxconsequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows.The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing arecognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting foruncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant taxauthority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amountrecognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with therelevant tax authority. The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability for the years endedDecember 31, 2015 and 2014.In the fourth quarter of 2015, the Company adopted Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes(“ASU 2015-17”). In accordance with ASU 2015-17, all deferred tax assets and liabilities, along with any related valuation allowance, are classified asnoncurrent on the balance sheet as of December 31, 2015. Prior periods were not retrospectively adjusted.Fair Value of Financial and Non-Financial InstrumentsThe carrying values of cash and cash equivalents, accounts receivable, accounts payable and other payables approximate their respective fairmarket values due to their short-term maturities. The Company’s derivative instruments and ARO are also recorded on the Company’s Consolidated BalanceSheet at amounts which approximate fair market value. See Note 3 — Fair Value Measurements.Recent Accounting PronouncementsRevenue RecognitionIn May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). Theobjective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customercontracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No.2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effectivefor annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluatingthe effect that adopting this guidance will have on its financial position, cash flows and results of operations.Going ConcernIn August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as aGoing Concern (“ASU 2014-15”). ASU 2014-15 codifies in GAAP management’s responsibility to evaluate whether there is substantial doubt about anentity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual reporting period endingafter December 15, 2016 and for annual periods and interim periods thereafter. The adoption of this guidance will not impact the Company’s financialposition, cash flows or results of operations, but could result in additional disclosures.84Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExtraordinary ItemsIn January 2015, the FASB issued Accounting Standards Update No. 2015-01, Simplifying Income Statement Presentation by Eliminating theConcept of Extraordinary Items (“ASU 2015-01”). ASU 2015-01 removes the concept of extraordinary items from GAAP. Under existing guidance, an entityis required to separately disclose extraordinary items, net of tax, in the income statement after income from continuing operations if an event or transaction isof an unusual nature and occurs infrequently. This separate, net-of-tax presentation will no longer be allowed. ASU 2015-01 is effective for fiscal yearsbeginning after December 15, 2015, including interim periods within those years. The Company does not expect the adoption of this guidance to have amaterial impact on its financial position, cash flows or results of operations.InventoryIn July 2015, the FASB issued Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”). ASU 2015-11 changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, first out(FIFO) or average cost methods. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those years.The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.Business CombinationsIn September 2015, the FASB issued Accounting Standards Update No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments(“ASU 2015-16”), which eliminates the requirement for an acquirer in a business combination to restate prior period financial statements for measurementperiod adjustments. ASU 2015-16 requires that the cumulative impact of measurement period adjustments on current and prior periods be recognized in thereporting period in which the adjustment amount is determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, includinginterim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flowsand results of operations.Financial InstrumentsIn January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and FinancialLiabilities (“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in netincome. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments.ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginningafter December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will haveon its financial position, cash flows and results of operations.3. Fair Value MeasurementsIn accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fairvalue on a recurring basis. The Company recognizes its non-financial assets and liabilities, such as ARO and proved oil and natural gas properties uponimpairment, at fair value on a non-recurring basis.As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderlytransaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions thatmarket participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuationtechnique. These inputs can be readily observable, market corroborated or generally unobservable.The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highestpriority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservableinputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are thosein which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as ofthe reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarilyindustry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and currentmarket and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions areobservable in85Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsthe marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at whichtransactions are executed in the marketplace.Level 3 — Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result inmanagement’s best estimate of fair value.Financial Assets and LiabilitiesAs required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair valuemeasurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets andliabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’sfinancial assets and liabilities that were accounted for at fair value on a recurring basis: At fair value as of December 31, 2015 Level 1 Level 2 Level 3 Total (In thousands)Assets: Money market funds$742 $— $— $742Commodity derivative instruments (see Note 4)— 155,473 — 155,473Total assets$742 $155,473 $— $156,215 At fair value as of December 31, 2014 Level 1 Level 2 Level 3 Total (In thousands)Assets: Money market funds$742 $— $— $742Commodity derivative instruments (see Note 4)— 315,507 — 315,507Total assets$742 $315,507 $— $316,249The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’sConsolidated Balance Sheet at December 31, 2015 and 2014. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds havedaily liquidity, quoted prices for the underlying investments can be obtained, and there are active markets for the underlying investments.The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include oil collars and swaps. The fairvalues of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reportsprovided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has thethird-party preparer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. The third-partypreparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The significant inputs usedare crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. However, the Company does not have access to thespecific proprietary valuation models or inputs used by its counterparties or third-party preparer. The Company compares the third-party preparer’s valuationto counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in crudeoil forward price curves. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, asrequired by GAAP. The Company calculates the credit adjustment for derivatives in an asset position using current credit default swap values for eachcounterparty. The credit adjustment for derivatives in a liability position is based on the Company’s market credit spread. Based on these calculations, theCompany recorded a downward adjustment to the fair value of its net derivative asset in the amount of $0.3 million and $0.6 million at December 31, 2015and 2014, respectively.There were no transfers between fair value levels during the years ended December 31, 2015 and 2014.Fair Value of Other Financial Instruments86Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe Company’s financial instruments, including certain cash and cash equivalents, accounts receivable and accounts payable, are carried at cost,which approximates fair value due to the short-term maturity of these instruments. At December 31, 2015, the Company’s cash equivalents were all Level 1assets.The carrying amount of the Company’s long-term debt reported in the Consolidated Balance Sheet at December 31, 2015 is $2,302.6 million, whichincludes $2,200.0 million of senior unsecured notes and $138.0 million of borrowings under the Company’s revolving credit facility (see Note 9 — Long-Term Debt). The fair value of the Company’s senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, is $1,440.0million at December 31, 2015.Non-Financial Assets and LiabilitiesAsset retirement obligations. The carrying amount of the Company’s ARO in the Company’s Consolidated Balance Sheet at December 31, 2015 was$35.8 million (see Note 10 — Asset Retirement Obligations). The Company determines the ARO by calculating the present value of estimated future cashflows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of aliability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation arenumerous assumptions and judgments, including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in thelegal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs. To the extent future revisions to these assumptionsimpact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.Impairment. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that adecline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its proved oiland natural gas properties then compares such amounts to the carrying amount of the proved oil and natural gas properties to determine if the carryingamount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of theproved oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include,but are not limited to, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costsusing estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount ratescommensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3inputs.Due to lower expected future oil prices, the Company reviewed its proved oil and natural gas properties for impairment as of December 31, 2015 and2014. As of December 31, 2015, the Company had certain proved oil and natural gas properties held for sale (see Note 7 — Assets Held for Sale). TheCompany recorded an impairment loss of $9.4 million, which was included in earnings in its exploration and production segment for the year endedDecember 31, 2015, to adjust the carrying value of these assets, net of the associated ARO liabilities, of $25.9 million to their estimated fair value of $16.5million. The fair value was determined based on the expected sales price as negotiated with potential buyers. For the year ended December 31, 2014, theCompany determined that the carrying value exceeded expected undiscounted cash flows for certain legacy wells that have been producing fromconventional reservoirs such as the Madison, Red River and other formations in the Williston Basin other than the Bakken or Three Forks formations. As aresult, these assets, with a carrying amount of $76.4 million, were written down to their fair value of $36.4 million, resulting in an impairment charge of $40.0million, which was included in earnings in the Company’s exploration and production segment for the year ended December 31, 2014. The fair value of theseassets was measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs used to determine the fairvalue included estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, and (iv) a weighted average cost of capitalrate based on the assumptions of a market participant. The market-based weighted average cost of capital rate is subjected to additional project-specificrisking factors. The underlying commodity prices embedded in the Company’s estimated cash flows were determined using NYMEX forward swap prices forfive years, escalating 3% per year thereafter as of December 31, 2015 and holding the fifth year price constant thereafter as of December 31, 2014. As ofDecember 31, 2015, a 3% inflation factor was also applied to the future operating and development costs after five years. No impairment charges on provedoil and natural gas properties were recorded for the year ended December 31, 2013.In addition, as a result of expiring leases and periodic assessments of unproved properties, the Company recorded non-cash impairment charges onits unproved oil and gas properties of $36.6 million, $7.3 million, and $1.2 million for the years ended December 31, 2015, 2014 and 2013, respectively.4. Derivative InstrumentsThe Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2015, the Companyutilized two-way costless collar options and swaps to reduce the volatility of oil prices on a87Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentssignificant portion of the Company’s future expected oil production. A two-way collar is a combination of options: a sold call and a purchased put. Thepurchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes undercontract. A swap is a sold call and a purchased put established at the same price (both ceiling and floor).All derivative instruments are recorded on the Company’s Consolidated Balance Sheet as either assets or liabilities measured at their fair value (seeNote 3 — Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter intosuch instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value arerecognized in the other income (expense) section of the Company’s Consolidated Statement of Operations as a gain or loss on derivative instruments. TheCompany’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from thecounterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments and do not include a recovery ofcosts that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’sConsolidated Statement of Cash Flows.As of December 31, 2015, the Company had the following outstanding commodity derivative instruments, all of which settle monthly based on theNYMEX West Texas Intermediate crude oil index price (“WTI”):SettlementPeriod DerivativeInstrument Total NotionalAmount of Oil Weighted Average Prices Fair ValueAsset(Liability) Swap Floor Ceiling (Barrels) ($/Barrel) (In thousands)2016 Two-way collars 155,000 $86.00 $103.42 7,4642016 Swaps 9,452,000 $54.89 132,2332017 Swaps 2,049,000 $53.17 15,1092018 Swaps 124,000 $53.62 667 $155,473The following table summarizes the location and fair value of all outstanding commodity derivative instruments recorded in the Company’sConsolidated Balance Sheet for the periods presented: Fair Value as of December 31,Commodity Balance Sheet Location 2015 2014 (In thousands)Crude oil Derivative instruments — current assets $139,697 $302,159Crude oil Derivative instruments — non-current assets 15,776 13,348Total derivative instruments $155,473 $315,507The following table summarizes the location and amounts of gains and losses from the Company’s commodity derivative instruments recorded inthe Company’s Consolidated Statement of Operations for the periods presented: Year Ended December 31,Statement of Operations Location 2015 2014 2013 (In thousands)Net gain (loss) on derivative instruments $210,376 $327,011 $(35,432)In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose bothgross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactionssubject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis bycounterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, grossamounts are offset to determine the net amounts presented in the Company’s Consolidated Balance Sheet.88Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe following tables summarize gross and net information about the Company’s commodity derivative instruments for the periods presented:Offsetting of Derivative Assets Gross Amounts of Recognized Assets Gross Amounts Offset in theBalance Sheet Net Amounts of Assets Presented in theBalance Sheet (In thousands)As of December 31, 2015 $155,473 $— $155,473As of December 31, 2014 $331,121 $(15,614) $315,507 Offsetting of Derivative Liabilities Gross Amounts of Recognized Liabilities Gross Amounts Offset in theBalance Sheet Net Amounts of Liabilities Presented in theBalance Sheet (In thousands)As of December 31, 2015 $— $— $—As of December 31, 2014 $15,614 $(15,614) $—5. Property, Plant and EquipmentThe following table sets forth the Company’s property, plant and equipment: December 31, 2015 2014 (In thousands)Proved oil and gas properties(1)$5,655,759 $5,156,875Less: Accumulated depreciation, depletion, amortization and impairment(1,428,427) (1,043,121)Proved oil and gas properties, net4,227,332 4,113,754Unproved oil and gas properties628,642 809,265Other property and equipment443,265 313,439Less: Accumulated depreciation(80,997) (49,672)Other property and equipment, net362,268 263,767Total property, plant and equipment, net$5,218,242 $5,186,786__________________ (1)Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $30.7 million and $36.9 million atDecember 31, 2015 and 2014, respectively.6. Acquisitions and DivestituresAcquisitionsThe following table summarizes the consideration paid, including customary post close adjustments, for the Company’s 2013 acquisitions and thefair value of the assets acquired and liabilities assumed as of the acquisition dates.89Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents West Williston East Nesson (In thousands)Consideration given to the sellers: Cash$1,475,361 $56,793Forgiveness of debt— (43)Total consideration1,475,361 56,750Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Proved developed properties519,712 32,053Proved undeveloped properties165,907 1,807Unproved lease acquisition costs787,589 23,369Other property and equipment13,157 —Inventory3,181 148Accounts receivable276 —Total assets acquired1,489,822 57,377Liabilities assumed: Asset retirement obligations6,598 307Revenues payable7,863 320Total liabilities assumed14,461 627Total identifiable net assets$1,475,361 $56,750West Williston acquisition. On October 1, 2013, the Company completed a purchase and sale agreement with two undisclosed private sellers (the“Sellers”), pursuant to which the Company agreed to purchase approximately 136,000 net acres in its West Williston area in the Williston Basin for aggregateconsideration of $1,475.4 million in cash (the “West Williston Acquisition”).The West Williston Acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired andliabilities assumed as of the October 1, 2013 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability inan orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of marketparticipants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimatedquantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates ofproduction, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 3 — FairValue Measurements. The Company recorded the assets acquired and liabilities assumed in the West Williston Acquisition at their estimated fair value of$1,475.4 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in nogoodwill or bargain purchase being recognized.The results of operations for the West Williston Acquisition have been included in the Company’s consolidated financial statements since theOctober 1, 2013 closing date, including approximately $57.6 million of total revenue and $14.9 million of operating income for the year ended December31, 2013. In addition, the Company included $2.0 million of costs related to the West Williston Acquisition in general and administrative expenses on itsConsolidated Statement of Operations for the year ended December 31, 2013.Summarized below are the consolidated results of operations for the year ended December 31, 2013, on an unaudited pro forma basis, as if theacquisition and related financing had occurred on January 1, 2012. The unaudited pro forma financial information was derived from the historicalconsolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the West Williston Acquisitionproperties, which were derived from the historical accounting records of the Sellers. The unaudited pro forma financial information does not purport to beindicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is suchinformation indicative of the Company’s expected future results of operations.90Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents Year Ended December 31, 2013 (In thousands) UnauditedRevenues$1,297,545Net income231,217East Nesson acquisitions. On September 26, 2013, the Company acquired certain oil and natural gas assets totaling approximately 25,000 net acresin its East Nesson area in the Williston Basin for total consideration of $56.8 million (the “East Nesson Acquisitions,” and together with the West WillistonAcquisition, the “2013 Acquisitions”). As part of the East Nesson Acquisitions, the Company also agreed to invest, expend and/or incur expenses of $8.2million in connection with drilling and completion activities for certain wells and was obligated to pay the seller the remaining committed amount of $3.2million not fulfilled as of July 1, 2015.The results of operations for the East Nesson Acquisitions have been included in the Company’s consolidated financial statements since theSeptember 26, 2013 closing date. Pro forma information is not presented as the pro forma results would not be materially different from the informationpresented in the Company’s Consolidated Statement of Operations.The Company did not have any significant acquisitions for the years ended December 31, 2015 and 2014.DivestituresOn March 5, 2014, the Company completed the sale of certain non-operated properties in and around its Sanish position (the “Sanish Divestiture”)for cash proceeds of approximately $324.9 million, which includes customary post close adjustments. The Company recognized a $187.0 million gain onsale of properties in its Consolidated Statement of Operations for the year ended December 31, 2014. The transaction was structured as an Internal RevenueCode Section 1031 like-kind exchange for tax purposes and as such did not give rise to any current taxable gain.7. Assets Held for SaleNet assets held for sale represent the assets that were expected to be sold, net of liabilities, which were expected to be assumed by the purchaser. Asof December 31, 2015, certain legacy wells that have been producing from conventional reservoirs such as the Madison, Red River and other formations inthe Williston Basin other than the Bakken or Three Forks formations were held for sale. These assets are in the Company’s exploration and productionsegment. The Company recorded a loss of $9.4 million, which was included in impairment of oil and gas properties on the Company’s ConsolidatedStatement of Operations for the year ended December 31, 2015, to adjust the carrying value of these assets to their estimated fair value, determined based onthe expected sales price as negotiated with potential buyers, less costs to sell. The Company expects to sell these assets within one year. The Company didnot have assets classified as held for sale as of December 31, 2014. The following table presents balance sheet data related to the assets held for sale: December 31, 2015 (In thousands)Assets: Oil and gas properties$120,926Less: accumulated depreciation, depletion, amortization and impairment94,198Total assets$26,728Liabilities: Asset retirement obligation$(10,228)Total liabilities$(10,228)Net assets$16,5008. Accrued LiabilitiesThe Company’s accrued liabilities consist of the following: 91Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents December 31, 2015 2014 (In thousands)Accrued capital costs$110,313 $361,034Accrued lease operating expenses18,448 26,706Accrued general and administrative expenses18,404 12,225Accrued well services and midstream operating expenses13,517 4,845Other accrued liabilities6,987 5,569Total accrued liabilities$167,669 $410,379Accrued liabilities represent the Company’s estimated current payment obligations for materials and services provided by its vendors, for whichinvoices have not yet been received or fully processed. Invoices that have been fully processed, but not yet paid, are recorded as accounts payable.In addition, the Company had revenue suspense of $58.4 million, royalties payable of $31.3 million and production taxes payable of $13.8 millionincluded in revenues and production taxes payable on the Company’s Consolidated Balance Sheet for the year ended December 31, 2015. For the year endedDecember 31, 2014, the Company had revenue suspense of $152.3 million, royalties payable of $38.1 million and production taxes payable of $19.5 millionincluded in revenues and production taxes payable on the Company’s Consolidated Balance Sheet. Revenue suspense represents proceeds from the sale ofoil and natural gas production that have been processed by the Company on behalf of third parties that cannot be disbursed to such third parties until certainissues are resolved, such as title issues or missing contact information.9. Long-Term DebtSenior unsecured notes. During 2011 and 2012, the Company issued $400.0 million of 7.25% senior unsecured notes due February 1, 2019 (the“2019 Notes”), $400.0 million of 6.5% senior unsecured notes due November 1, 2021 (the “2021 Notes”) and $400.0 million of 6.875% senior unsecurednotes due January 15, 2023 (the “2023 Notes”), which resulted in aggregate net proceeds to the Company of $1,175.8 million. The Company has used theproceeds from these notes to fund its exploration, development and acquisition program and for general corporate purposes. During 2013, the Companyissued $1,000.0 million of 6.875% senior unsecured notes due March 15, 2022 (the “2022 Notes”), which resulted in aggregate net proceeds to the Companyof $983.6 million. The Company used the proceeds from the 2022 Notes to fund the West Williston Acquisition (see Note 6 — Acquisitions andDivestitures). Interest on the 2019 Notes, the 2021 Notes, the 2022 Notes and the 2023 Notes (collectively, the “Notes”) is payable semi-annually in arrears.The Notes were issued under indentures containing provisions that are substantially the same, as amended and supplemented by supplementalindentures (collectively the “Indentures”), among the Company, along with its material subsidiaries (the “Guarantors”), and U.S. Bank National Association,as trustee. The Notes are guaranteed on a senior unsecured basis by the Company’s Guarantors, which are 100% owned by the Company. These guarantees arefull and unconditional and joint and several among the Guarantors, subject to certain customary release provisions, as follows:•in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger orconsolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary (as defined inthe Indentures) of the Company;•in connection with any sale or other disposition of the capital stock of that Guarantor (including by way of merger or consolidation) to a personthat is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, such that, immediatelyafter giving effect to such transaction, such Guarantor would no longer constitute a subsidiary of the Company;•if the Company designates any Restricted Subsidiary that is a Guarantor to be an unrestricted subsidiary in accordance with the Indenture;•upon legal defeasance or satisfaction and discharge of the Indenture; or•upon the liquidation or dissolution of a Guarantor, provided no event of default occurs under the Indentures as a result thereof.Prior to certain dates, the Company has certain options to redeem up to 35% of the Notes at a certain redemption price based on a percentage of theprincipal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurswithin 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after suchredemption. Prior to certain dates, the Company92Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentshas the option to redeem some or all of the Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus anapplicable make-whole premium and accrued and unpaid interest to the redemption date. The Company estimates that the fair value of these options isimmaterial at December 31, 2015 and 2014.The Indentures restrict the Company’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt or enter into sale and leasebacktransactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions withaffiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to certain exceptions andqualifications. If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services andno Default (as defined in the Indentures) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries willcease to be subject to such covenants.The Indentures contain customary events of default, including:•default in any payment of interest on any Note when due, continued for 30 days;•default in the payment of principal or premium, if any, on any Note when due;•failure by the Company to comply with its other obligations under the Indentures, in certain cases subject to notice and grace periods;•payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principalamount of $10.0 million or more;•certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary (as defined in the Indentures) or group ofRestricted Subsidiaries that, taken together, would constitute a Significant Subsidiary;•failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together, would constitute a SignificantSubsidiary to pay certain final judgments aggregating in excess of $10.0 million within 60 days; and•any guarantee of the Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied ordisaffirmed by its maker.On October 26, 2015, the Company, the Company’s Guarantors, and U.S. Bank National Association, as trustee, entered into supplementalindentures respecting amendments (the “Amendments”) to the Indentures governing the Company’s outstanding 2019 Notes, 2021 Notes and 2023 Notes(collectively, the “Consent Notes”) following the Company’s receipt of requisite consents of the holders of the Consent Notes pursuant to consentsolicitations that commenced on October 6, 2015. The Amendments amend the basket for secured credit facilities indebtedness in each of the Indentures by(i) adding a provision that allows the Company to incur secured credit facilities indebtedness up to the amount of the Company’s borrowing base at the timeof the incurrence, but not to exceed $1,525.0 million and (ii) adding, deleting or revising several related definitions in the Indentures, which changesgenerally restrict the Company’s ability to incur second-lien indebtedness.Senior secured revolving line of credit. On April 5, 2013, the Company, as parent, and OPNA, as borrower, entered into a second amended andrestated credit agreement (the “Second Amended Credit Facility”), which has an overall senior secured line of credit of $2,500.0 million as of December 31,2015. The Second Amended Credit Facility is restricted to the borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1and October 1 of each year. On April 13, 2015, the Company entered into its third amendment to the Second Amended Credit Facility (the “ThirdAmendment”), which extended the maturity date of the Second Amended Credit Facility to April 13, 2020, provided that the 2019 Notes are retired orrefinanced 90 days prior to their maturity. In connection with the Third Amendment, the lenders under the Second Amended Credit Facility (the “Lenders”)completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2015, resulting in a borrowing base decrease from $2,000.0million to $1,700.0 million. The Company increased the Lenders’ aggregate elected commitment from $1,500.0 million to $1,525.0 million. The ThirdAmendment also increased the Lenders in the bank group to 18 financial institutions supporting the Company’s borrowing base facility. On October 6, 2015,the Lenders completed their regular semi-annual redetermination of the borrowing base of the Second Amended Credit Facility, resulting in a borrowing basedecrease from $1,700.0 million to $1,525.0 million, which was equal to the Lenders’ aggregate elected commitment.Borrowings under the Second Amended Credit Facility are collateralized by perfected first priority liens and security interests on substantially all ofthe Company’s assets, including mortgage liens on oil and natural gas properties having at least 80% (as of December 31, 2015) of the reserve value asdetermined by reserve reports.93Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBorrowings under the Second Amended Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings(including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a London interbank offered rate(“LIBOR”) loan or a domestic bank prime interest rate loan (defined in the Second Amended Credit Facility as an Alternate Based Rate or “ABR” loan). As ofDecember 31, 2015, any outstanding LIBOR and ABR loans would have borne their respective interest rates plus the applicable margin indicated in thefollowing table: Ratio of Total Outstanding Borrowings to Borrowing BaseApplicable Marginfor LIBOR Loans Applicable Marginfor ABR LoansLess than .25 to 11.50% 0.00%Greater than or equal to .25 to 1 but less than .50 to 11.75% 0.25%Greater than or equal to .50 to 1 but less than .75 to 12.00% 0.50%Greater than or equal to .75 to 1 but less than .90 to 12.25% 0.75%Greater than or equal to .90 to 12.50% 1.00%An ABR loan may be repaid at any time before the scheduled maturity of the Second Amended Credit Facility upon the Company providingadvance notification to the Lenders. Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last businessday in March, June, September and December. The Company has the option to convert an ABR loan to a LIBOR-based loan upon providing advancenotification to the Lenders. The minimum available loan term is one month and the maximum available loan term is six months for LIBOR-based loans.Interest for LIBOR loans is paid upon maturity of the loan term. Interim interest is paid every three months for LIBOR loans that have loan terms greater thanthree months. At the end of a LIBOR loan term, the Second Amended Credit Facility allows the Company to elect to repay the borrowing, continue a LIBORloan with the same or differing loan term or convert the borrowing to an ABR loan.On a quarterly basis, the Company also pays a 0.375% (as of December 31, 2015) annualized commitment fee on the average amount of borrowingbase capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.As of December 31, 2015, the Second Amended Credit Facility contained covenants that included, among others:•a prohibition against incurring debt, subject to permitted exceptions;•a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;•a prohibition against making investments, loans and advances, subject to permitted exceptions;•restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted exceptions;•restrictions on merging and selling assets outside the ordinary course of business;•restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;•a provision limiting oil and natural gas derivative financial instruments;•a requirement that the Company maintain a ratio of consolidated EBITDAX (as defined in the Second Amended Credit Facility) toconsolidated Interest Expense (as defined in the Second Amended Credit Facility) of no less than 2.5 to 1.0 for the four quarters endedon the last day of each quarter; and•a requirement that the Company maintain a Current Ratio (as defined in the Second Amended Credit Facility) of consolidated currentassets (including unused borrowing base committed capacity and with exclusions as described in the Second Amended Credit Facility)to consolidated current liabilities (with exclusions as described in the Second Amended Credit Facility) of no less than 1.0 to 1.0 as ofthe last day of any fiscal quarter.The Second Amended Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declareall amounts outstanding under the Second Amended Credit Facility to be immediately due and payable.94Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAs of December 31, 2015, the Company had $138.0 million of borrowings and $5.2 million of outstanding letters of credit issued under the SecondAmended Credit Facility, resulting in an unused borrowing base capacity of $1,381.8 million. As of December 31, 2015 and 2014, the weighted averageinterest rate on borrowings under the Second Amended Credit Facility was 1.9% and 1.8%, respectively. The Company was in compliance with the financialcovenants of the Second Amended Credit Facility as of December 31, 2015.The Company has $400.0 million of Notes maturing in 2019 and indebtedness under the Second Amended Credit Facility that becomes due in2020. The Company does not have any other debt that matures within the five years ending December 31, 2020.Deferred financing costs. As of December 31, 2015, the Company had $42.9 million of deferred financing costs related to the Notes and the SecondAmended Credit Facility, which are being amortized over the respective terms of the Notes and the Second Amended Credit Facility. Deferred financing costsof $35.4 million related to the Notes are included in long-term debt on the Company’s Consolidated Balance Sheet as of December 31, 2015 in accordancewith ASU 2015-03, which the Company adopted in the fourth quarter of 2015 (see Note 2 — Summary of Significant Accounting Policies). Deferredfinancing costs of $7.5 million related to the Second Amended Credit Facility are included in other assets on the Company’s Consolidated Balance Sheet atDecember 31, 2015. Amortization of deferred financing costs recorded for the year ended December 31, 2015, 2014 and 2013 was $7.2 million, $6.4 millionand $4.5 million, respectively. These costs are included in interest expense on the Company’s Consolidated Statement of Operations.10. Asset Retirement ObligationsThe following table reflects the changes in the Company’s ARO during the years ended December 31, 2015 and 2014: Year Ended December 31, 2015 2014 (In thousands)Asset retirement obligation — beginning of period$42,549 $36,458Liabilities incurred during period1,245 5,376Liabilities settled during period(1)(218) (2,065)Accretion expense during period(2)2,223 1,917Revisions to estimates241 863Liabilities held for sale(3)(10,228) —Asset retirement obligation — end of period$35,812 $42,549__________________ (1)Liabilities settled during the year ended December 31, 2014 include ARO related to the properties sold in the Sanish Divestiture.(2)Included in depreciation, depletion and amortization on the Company’s Consolidated Statement of Operations.(3)Represents ARO related to the properties held for sale as of December 31, 2015 (see Note 7 — Assets Held for Sale).At both December 31, 2015 and 2014, the current portion of the total ARO balance was approximately $0.5 million and is included in accruedliabilities on the Company’s Consolidated Balance Sheet.11. Income TaxesThe Company’s income tax expense (benefit) consists of the following:95Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents Year Ended December 31, 2015 2014 2013 (In thousands)Current: Federal$(9) $134 $475State— — — (9) 134 475Deferred: Federal(11,667) 273,576 122,853State(4,447) 33,881 11,730 (16,114) 307,457 134,583Total income tax expense (benefit)$(16,123) $307,591 $135,058The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate for the years endedDecember 31, 2015, 2014 and 2013, is set forth below: Year Ended December 31, 2015 2014 2013 (%) (In thousands) (%) (In thousands) (%) (In thousands)U.S. federal tax statutory rate35.00 % $(19,730) 35.00 % $285,064 35.00% $127,056State income taxes, net of federal income taxbenefit5.11 % (2,883) 2.81 % 22,901 2.06% 7,469Non-deductible stock-based compensation(shortfall)(10.17)% 5,734 — % — —% —Other(1.34)% 756 (0.05)% (374) 0.14% 533Annual effective tax expense (benefit)28.60 % $(16,123) 37.76 % $307,591 37.20% $135,058The effective tax rate was lower for the year ended December 31, 2015 due to the Company’s pre-tax loss and the impact of permanent differences.The permanent differences were primarily between amounts expensed for book purposes versus the amounts deductible for income tax purposes related tostock-based compensation vesting during the year ended December 31, 2015 at stock prices lower than the grant date values. The impact of these permanentdifferences was partially offset by a reduction in the North Dakota statutory tax rate in 2015. For the years ended December 31, 2014 and 2013, theCompany’s effective tax rate differed from the federal statutory rate of 35% primarily due to state income taxes. Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2015 and 2014, were as follows: Year Ended December 31, 2015 2014 (In thousands)Deferred tax assets Net operating loss carryforward$121,248 $35,650Bonus and stock-based compensation11,222 11,025Other tax attribute carryovers1,601 1,349Total deferred tax assets134,071 48,024Deferred tax liabilities Oil and natural gas properties696,498 566,382Derivative instruments45,728 105,911Total deferred tax liabilities742,226 672,293Total net deferred tax liability$608,155 $624,26996Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe Company generated a federal net operating tax loss of $244.4 million and accrued $9,000 of current income tax benefit for the year endedDecember 31, 2015. The net operating loss carryforwards consist of $333.9 million of federal net operating loss carryforwards, which expire between 2030and 2035, and $266.5 million of state net operating loss carryforwards, which expire between 2017 and 2035. The tax benefits of carryforwards are recordedas an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not. When the future utilization of someportion of the carryforwards is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded tax benefits from suchassets. Management believes that the Company’s taxable temporary differences and future taxable income will more likely than not be sufficient to utilizesubstantially all its tax carryforwards prior to their expiration.Pursuant to authoritative guidance, the Company’s $121.2 million deferred tax asset related to net operating loss carryforwards is net of $3.6 millionof unrealized excess tax benefits related to excess stock-based compensation on federal and state net operating losses of $9.6 million and $7.6 million,respectively.Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statementrecognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2015, the Company had no unrecognized taxbenefits. With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in itsConsolidated Statement of Operations. The Company files income tax returns in the U.S. federal jurisdiction and in North Dakota, Montana and Texas. TheIRS has concluded an audit of the Company’s 2013 income tax return with no material change. The Company’s other income tax returns have not beenaudited by the IRS or any state jurisdiction. Its statute of limitation for the year ended December 31, 2015 will expire in 2019. The Company’s earliest openyear in its key jurisdictions is 2012 for both the U.S. federal jurisdiction and various U.S. states, however, net operating losses originating in prior years aresubject to examination when utilized.In accordance with ASU 2015-17, which the Company adopted in the fourth quarter of 2015 (see Note 2 — Summary of Significant AccountingPolicies), all deferred tax assets and liabilities, along with any related valuation allowance, are classified as noncurrent on the balance sheet as ofDecember 31, 2015. Prior periods were not retrospectively adjusted, and the current portion of the Company’s net deferred income taxes was a liability of$97.5 million at December 31, 2014, which was primarily related to derivative instruments.12. Stock-Based CompensationRestricted stock awards. The Company has granted restricted stock awards to employees and directors under its Amended and Restated 2010 LongTerm Incentive Plan, the majority of which vest over a three-year period. The maximum number of shares available for grant under the Amended and Restated2010 Long Term Incentive Plan is 8,550,000. The fair value of restricted stock grants is based on the closing sales price of the Company’s common stock onthe date of grant. Compensation expense is recognized ratably over the requisite service period. The Company assumed annual forfeiture rates by employeegroup ranging from 0% to 16.9% based on the Company’s forfeiture history for this type of award.The following table summarizes information related to restricted stock held by the Company’s employees and directors for the periods presented: Shares Weighted AverageGrant DateFair Value per ShareNon-vested shares outstanding December 31, 20141,370,418 $40.03Granted1,328,560 14.28Vested(675,165) 36.77Forfeited(182,664) 26.08Non-vested shares outstanding December 31, 20151,841,149 $24.03Stock-based compensation expense recorded for restricted stock awards was $21.4 million, $18.2 million and $10.2 million, respectively, for each ofthe years ended December 31, 2015, 2014 and 2013, and is included in general and administrative expenses on the Company’s Consolidated Statement ofOperations. The fair value of awards vested was $9.5 million, $18.3 million and $6.5 million for the years ended December 31, 2015, 2014 and 2013. Theweighted average grant date fair value of restricted stock awards granted was $14.28 per share, $42.55 per share and $38.64 per share for the years endedDecember 31, 2015, 2014 and 2013. Unrecognized expense as of December 31, 2015 for all outstanding restricted stock awards was $29.3 million and will berecognized over a weighted average period of 1.7 years.97Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPerformance share units. The Company has granted PSUs to officers of the Company under its Amended and Restated 2010 Long Term IncentivePlan. The PSUs are awards of restricted stock units, and each PSU that is earned represents the right to receive one share of the Company’s common stock. TheCompany assumed annual forfeiture rates by employee group ranging from 2.4% to 4.9% based on the Company’s forfeiture history for the employee groupsreceiving PSUs.Each grant of PSUs is subject to a designated three-year initial performance period. The number of PSUs to be earned is subject to a marketcondition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock againstthe TSR achieved by a defined peer group at the end of the performance period. Depending on the Company’s TSR performance relative to the defined peergroup, award recipients will earn between 0% and 200% of the initial PSUs granted. If less than 200% of the initial PSUs granted are earned at the end of theinitial three-year performance period, then the performance period will be extended an additional year to give the award recipients the opportunity to earn upto an aggregate of 200% of the initial PSUs granted.The following table summarizes information related to PSUs held by the Company’s officers for the periods presented: Units Weighted AverageGrant DateFair Value per UnitNon-vested PSUs at December 31, 2014402,140 $36.68Granted425,590 11.20Vested(92,038) 26.22Forfeited(71,438) 25.97Non-vested PSUs at December 31, 2015664,254 $22.96Stock-based compensation expense recorded for PSUs for the years ended December 31, 2015, 2014 and 2013 was $3.9 million, $3.1 million and$1.8 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. The fair value ofPSUs vested was $0.8 million for the year ended December 31, 2015. No PSUs vested during the years ended December 31, 2014 and 2013. The weightedaverage grant date fair value of PSUs granted was $11.20 per share, $41.71 per share and $42.01 per share for the years ended December 31, 2015, 2014 and2013. Unrecognized expense as of December 31, 2015 for all outstanding PSUs was $8.7 million and will be recognized over a weighted average period of2.2 years.The Company accounted for these PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The aggregategrant date fair value of the market-based awards was determined using a Monte Carlo simulation model, which results in an expected percentage of PSUs tobe earned during the performance period. The fair value of these PSUs is recognized on a straight-line basis over the performance period. As it is probable thata portion of the awards in each of the grants will be earned during the extended performance period, the grant date fair value is amortized over four years.However, if 200% of the initial PSUs granted are earned at the end of the initial three-year performance period, then the remaining compensation expense willbe accelerated in order to be fully recognized over three years. All compensation expense related to the PSUs will be recognized if the requisite performanceperiod is fulfilled, even if the market condition is not achieved.The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilisticassessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, risk-free interest rate, volatility and correlationcoefficients. The risk-free interest rate is the U.S. Treasury bond rate on the date of grant. The initial value is the average of the volume weighted averageprices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility is the standard deviation of theaverage percentage change in stock price over a historical period for the Company and each of its peers. The correlation coefficients are measures of thestrength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data.The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensationexpense of the PSUs granted during the periods presented: 98Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents 2015 2014 2013Forecast period (years)4 4 4Risk-free interest rate0.99% 1.12% 0.65%Oasis stock price volatility50.11% 44.49% 47.48%The Monte Carlo simulation model resulted in an expected percentage of PSUs to be earned of 86%, 98% and 112% for the 2015, 2014 and 2013grants, respectively.Associated tax benefit. For the years ended December 31, 2015, 2014 and 2013, the Company had an associated tax benefit of $8.7 million, $8.4million and $4.5 million, respectively, related to all stock-based compensation.13. Common StockOn March 9, 2015, the Company completed a public offering of 36,800,000 shares of its common stock (including 4,800,000 shares issued pursuantto the underwriters’ option to purchase additional common stock) at an offering price of $12.80 per share. Net proceeds from the offering were $462.8 million,after deducting underwriting discounts and commissions and estimated offering expenses, of which $0.4 million is included in common stock and $462.4million is included in additional paid-in capital on the Company’s Condensed Consolidated Balance Sheet. The Company used the net proceeds to repayoutstanding indebtedness under its Second Amended Credit Facility and for general corporate purposes. The offering was made pursuant to an effective shelfregistration statement on Form S-3 filed with the Securities and Exchange Commission (the “SEC”) on July 15, 2014.On December 9, 2013, the Company completed a public offering of 7,000,000 shares of its common stock, par value $0.01 per share, at an offeringprice of $44.94 per share. Net proceeds from the offering were approximately $314.4 million, after deducting offering expenses, of which $70,000 is includedin common stock and $314.3 million is included in additional paid-in-capital on the Company’s Consolidated Balance Sheet. The Company used a portionof these net proceeds to repay $264.4 million of outstanding indebtedness under its Second Amended Credit Facility, and the remaining proceeds were usedto fund its exploration, development and acquisition program and for general corporate purposes. The offering was made pursuant to an effective shelfregistration statement on Form S-3 filed with the SEC on July 15, 2011.14. Earnings (Loss) Per ShareBasic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of sharesoutstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restrictedshares and PSUs outstanding during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to income (loss) available tocommon stockholders in the calculation of diluted earnings (loss) per share.The following is a calculation of the basic and diluted weighted average shares outstanding for the periods presented: Year Ended December 31, 2015 2014 2013 (In thousands)Basic weighted average common shares outstanding130,186 99,677 92,867Dilution effect of stock awards at end of period(1)— 688 544Diluted weighted average common shares outstanding130,186 100,365 93,411Anti-dilutive stock-based compensation awards2,842 980 634__________________ (1)No unvested stock awards were included in computing loss per share for the year ended December 31, 2015 because the effect was anti-dilutive.15. Business Segment InformationThe Company’s exploration and production segment is engaged in the acquisition and development of oil and natural gas properties. Revenues forthe exploration and production segment are derived from the sale of oil and natural gas production. The Company’s well services business segment (OWS)performs completion services for the Company’s oil and99Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsnatural gas wells operated by OPNA. Revenues for the well services segment are derived from providing well completion services, well completion productsales and tool rentals. The Company’s midstream services business segment (OMS) performs salt water gathering and disposal and other midstream servicesfor the Company’s oil and natural gas wells operated by OPNA. Revenues for the midstream segment are primarily derived from salt water pipeline transport,salt water disposal and fresh water sales. The revenues and expenses related to work performed by OWS and OMS for OPNA’s working interests are eliminatedin consolidation, and only the revenues and expenses related to non-affiliated working interest owners are included in the Company’s ConsolidatedStatement of Operations. These segments represent the Company’s three current operating units, each offering different products and services. TheCompany’s corporate activities have been allocated to the supported business segments accordingly.Management evaluates the performance of the Company’s business segments based on operating income, which is defined as segment operatingrevenues less operating expenses, including DD&A. The following table summarizes financial information for the Company’s three business segments for theperiods presented: Exploration andProduction Well Services MidstreamServices Eliminations Consolidated (In thousands)Year Ended December 31, 2015 Revenues from external customers$721,672 $44,294 $23,769 $— $789,735Inter-segment revenues— 177,184 80,926 (258,110) —Total revenues721,672 221,478104,695 (258,110) 789,735Operating income (loss)(177,512) 49,145 60,668 (46,465) (114,164)Other income (expense)58,542 52 (801) — 57,793Income (loss) before income taxes$(118,970) $49,197 $59,867 $(46,465) $(56,371)Total assets(1)$5,478,439 $470,614 $409,635 $(709,313) $5,649,375Capital expenditures(2)537,806 21,711 96,947 (46,465) 609,999Depreciation, depletion and amortization479,693 19,073 5,764 (19,208) 485,322Impairment of oil and gas properties46,109 — — — 46,109 Year Ended December 31, 2014 Revenues from external customers$1,304,004 $74,610 $11,614 $— $1,390,228Inter-segment revenues— 192,774 39,344 (232,118) —Total revenues1,304,004 267,384 50,958 (232,118) 1,390,228Operating income610,850 70,878 22,730 (58,806) 645,652Other income (expense)168,741 75 — — 168,816Income before income taxes$779,591 $70,953 $22,730 $(58,806) $814,468Total assets$5,772,959 $281,844 $212,685 $(358,412) $5,909,076Capital expenditures(2)1,525,168 37,292 68,939 (58,806) 1,572,593Depreciation, depletion and amortization406,960 14,080 3,744 (12,450) 412,334Impairment of oil and gas properties47,238 — — — 47,238 Year Ended December 31, 2013 Revenues from external customers$1,084,412 $51,845 $5,742 $— $1,141,999Inter-segment revenues— 128,841 23,488 (152,329) —Total revenues1,084,412 180,686 29,230 (152,329) 1,141,999Operating income473,178 56,322 17,509 (42,611) 504,398Other income (expense)(141,397) 16 — — (141,381)Income before income taxes$331,781 $56,338 $17,509 $(42,611) $363,017Total assets(1)$4,558,257 $78,359 $117,641 $(76,216) $4,678,041Capital expenditures(2)2,514,737 15,217 18,955 (42,611) 2,506,298Depreciation, depletion and amortization304,388 7,150 2,780 (7,263) 307,055100Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents__________________ (1)Total assets for the exploration and production segment include $26.7 million and $137.1 million of assets held for sale as of December 31, 2015 and2013, respectively.(2)Capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisition of oil andgas properties shown in the Company’s Consolidated Statement of Cash Flows because amounts reflected in the table include changes in accruedliabilities from the previous reporting period for capital expenditures, while the amounts presented in the Consolidated Statement of Cash Flows arepresented on a cash basis.16. Significant ConcentrationsMajor customers. For the year ended December 31, 2015, sales to Shell Trading (US) Company accounted for approximately 10% of the Company’stotal sales. For the years ended December 31, 2014 and 2013, sales to Musket Corporation accounted for approximately13% and 11% of the Company’s totalsales, respectively. No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2015, 2014 and 2013.Total sales include revenues from the Company’s exploration and production segment only, as OWS and OMS provide services to OPNA.Substantially all of the Company’s accounts receivable result from sales of oil and natural gas as well as joint interest billings (“JIB”) to third-party companies who have working interest payment obligations in projects completed by the Company. Statoil Oil & Gas LP and HRG, Inc. accounted forapproximately 17% and 10%, respectively, of the Company’s JIB receivables balance at December 31, 2015. Statoil Oil & Gas LP, Continental Resources,Inc. and Slawson Exploration Company, Inc. accounted for approximately 16%, 14% and 13%, respectively, of the Company’s JIB receivables balance atDecember 31, 2014.This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in thatthese entities may be similarly affected by changes in economic or other conditions, including the current downturn in oil prices. Management believes thatthe loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative oil and naturalgas purchasers in the Company’s producing regions.17. Commitments and ContingenciesIncluded below is a discussion of various future commitments of the Company as of December 31, 2015. The commitments under these arrangementsare not recorded in the accompanying Consolidated Balance Sheet. The amounts disclosed represent undiscounted cash flows on a gross basis, and noinflation elements have been applied.Lease obligations. The Company has operating leases for office space and other property and equipment. The Company incurred rental expense of$7.2 million, $5.0 million and $3.0 million for the years ended December 31, 2015, 2014 and 2013, respectively, included in general and administrativeexpenses on its Consolidated Statement of Operations.Future minimum annual rental commitments under non-cancelable leases at December 31, 2015 are as follows: (In thousands)2016$7,73720175,12120184,96920194,98620203,735Thereafter— $26,548Drilling contracts. As a result of its lowered 2015 capital expenditure program, the Company elected to early terminate certain drilling rig contractsand recorded a rig termination expense of $3.9 million in its Condensed Consolidated Statement of Operations for the year ended December 31, 2015. TheCompany did not elect to early terminate any drilling rig contracts during the year ended December 31, 2014 or 2013.101Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAs of December 31, 2015, the Company had certain drilling rig contracts with initial terms of one year or greater. In the event of early contracttermination under these contracts, the Company would be committed to pay approximately $5.7 million as of December 31, 2015 for the days remainingthrough the end of the primary terms of the contracts.Volume commitment agreements. As of December 31, 2015, the Company had certain agreements with an aggregate requirement to deliver ortransport a minimum quantity of approximately 35.0 MMBbl of crude oil, 23.0 MMBbl of natural gas liquids and 223.0 Bcf of natural gas, prior to anyapplicable volume credits, within specified timeframes, all of which are ten years or less. The estimable future commitments under these agreements are$448.4 million as of December 31, 2015. The future commitment under certain agreements cannot be estimated as it is based on fixed differentials relative toWTI under the agreements as compared to the differential relative to WTI for the Williston Basin for the production month.Purchase agreements. As of December 31, 2015, the Company had certain agreements for the purchase of fresh water with an aggregate futurecommitment of approximately $42.4 million.Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. Whilethe ultimate outcome and impact to the Company cannot be predicted with certainty, the Company believes that all such matters are without merit andinvolve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition,results of operations or cash flows. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues anundiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies wherean adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.On July 6, 2013, a freight train operated by Montreal, Maine and Atlantic Railway (“MMA”) carrying crude oil (the “Train”) derailed in Lac-Mégantic, Quebec. In March 2014, Oasis Petroleum Inc. and Oasis Petroleum LLC (“OP LLC”) were added to a group of over fifty named defendants,including other crude oil producers as well as the Canadian Pacific Railway, MMA and certain of its affiliates, owners and transloaders of the crude oil carriedby the Train, several lessors of tank cars, and the Attorney General of Canada, in a motion filed in the Quebec Superior Court to authorize a class-actionlawsuit seeking economic, compensatory and punitive damages, as well as costs for claims arising out of the derailment of the Train (Yannick Gagne, etc., etal. v. Rail World, Inc., etc., et al., Case No. 48006000001132) (the “Class-Action”). The motion generally alleges wrongful death and negligence in thefailure to provide for the proper and safe transportation of crude oil.The Company believes that all claims against Oasis Petroleum Inc. and OP LLC in connection with the derailment of the Train in Lac-Mégantic,Quebec are without merit.On August 7, 2013, MMA filed for bankruptcy protection in the Quebec Superior Court and the United States Bankruptcy Court in Bangor, Maine(together, the “Bankruptcy Actions”). The trustees appointed in the Bankruptcy Actions have negotiated settlement agreements with the majority of thenamed defendants in the Class-Action, including Oasis Petroleum Inc. and OP LLC. The Quebec Superior Court and the United States Bankruptcy Court haveissued orders approving the settlement agreements which were pending before them, and such orders have become final. Pursuant to the settlementagreements, Oasis Petroleum Inc. and OP LLC agreed to contribute to the compensation fund established for those suffering losses as a result of the Lac-Megantic derailment. Such contributions were fully covered by the Company’s insurance policies. Furthermore, the settlement agreements bar futurelitigation against Oasis Petroleum Inc. and OP LLC in Canada and the United States arising out of the Lac-Megantic derailment.18. Subsequent EventsThe Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition ordisclosure in the financial statements, other than as noted below.Derivative instruments. In January and February 2016, the Company entered into new swap and two-way costless collar agreements with a weightedaverage floor price of $41.58 per barrel for total notional amounts of 1,131,000 barrels, 2,159,000 barrels and 186,000 barrels, which settle in 2016, 2017 and2018, respectively, based on WTI. These derivative instruments do not qualify for and were not designated as a hedging instrument for accounting purposes.Sale of common stock. On February 2, 2016, the Company completed a public offering of 39,100,000 shares of its common stock (including5,100,000 shares issued pursuant to the underwriter’s option to purchase additional common stock) at a purchase price of $4.685 per share. Net proceeds fromthe offering were $182.9 million, after deducting underwriting discounts and commissions and estimated offering expenses. The Company intends to use thenet proceeds for general corporate purposes and to fund a portion of its 2016 capital expenditures. The offering was made pursuant to an effective shelfregistration statement on Form S-3 filed with the SEC on July 15, 2014.102Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCredit facility amendment. On February 23, 2016, the Lenders completed their regular semi-annual redetermination of the borrowing base of theSecond Amended Credit Facility scheduled for April 1, 2016, resulting in a decrease in the borrowing base and aggregate elected commitment from $1,525.0million to $1,150.0 million. The next redetermination of the borrowing base is scheduled for October 1, 2016.19. Condensed Consolidating Financial StatementsThe Notes (see Note 9 — Long-Term Debt) are guaranteed on a senior unsecured basis by the Guarantors, which are 100% owned by theCompany. These guarantees are full and unconditional and joint and several among the Guarantors. Certain of the Company’s immaterial wholly-ownedsubsidiaries do not guarantee the Notes (“Non-Guarantor Subsidiaries”).The following financial information reflects consolidating financial information of the parent company, Oasis Petroleum Inc. (“Issuer”), and itsGuarantors on a combined basis, prepared on the equity basis of accounting. The Non-Guarantor Subsidiaries are immaterial and, therefore, not presentedseparately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information maynot necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company hasnot presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would notprovide any additional information that would be material in evaluating the sufficiency of the Guarantors.103Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCondensed Consolidating Balance Sheet December 31, 2015 Parent/Issuer CombinedGuarantorSubsidiaries IntercompanyEliminations Consolidated (In thousands, except share data)ASSETS Current assets Cash and cash equivalents$777 $8,953 $— $9,730Accounts receivable – oil and gas revenues— 96,495 — 96,495Accounts receivable – joint interest and other15 100,899 — 100,914Accounts receivable – affiliates1,248 247,488 (248,736) —Inventory— 11,072 — 11,072Prepaid expenses278 7,050 — 7,328Derivative instruments— 139,697 — 139,697Other current assets— 50 — 50Total current assets2,318 611,704 (248,736) 365,286Property, plant and equipment Oil and gas properties (successful efforts method)— 6,284,401 — 6,284,401Other property and equipment— 443,265 — 443,265Less: accumulated depreciation, depletion, amortization andimpairment— (1,509,424) — (1,509,424)Total property, plant and equipment, net— 5,218,242 — 5,218,242Assets held for sale— 26,728 — 26,728Investments in and advances to subsidiaries4,573,172 — (4,573,172) —Derivative instruments— 15,776 — 15,776Deferred income taxes205,174 — (205,174) —Other assets100 23,243 — 23,343Total assets$4,780,764 $5,895,693 $(5,027,082) $5,649,375LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable$— $9,983 $— $9,983Accounts payable – affiliates247,488 1,248 (248,736) —Revenues and production taxes payable— 132,356 — 132,356Accrued liabilities10 167,659 — 167,669Accrued interest payable49,340 73 — 49,413Advances from joint interest partners— 4,647 — 4,647Other current liabilities— 6,500 — 6,500Total current liabilities296,838 322,466 (248,736) 370,568Long-term debt2,164,584 138,000 — 2,302,584Deferred income taxes— 813,329 (205,174) 608,155Asset retirement obligations— 35,338 — 35,338Liabilities held for sale— 10,228 — 10,228Other liabilities— 3,160 — 3,160Total liabilities2,461,422 1,322,521 (453,910) 3,330,033Stockholders’ equity Capital contributions from affiliates— 3,369,895 (3,369,895) —Common stock, $0.01 par value: 300,000,000 shares authorized;139,583,990 shares issued and 139,076,064 shares outstanding1,376 — — 1,376Treasury stock, at cost: 507,926 shares(13,620) — — (13,620)Additional paid-in-capital1,497,065 8,743 (8,743) 1,497,065Retained earnings834,521 1,194,534 (1,194,534) 834,521Total stockholders’ equity2,319,342 4,573,172 (4,573,172) 2,319,342Total liabilities and stockholders’ equity$4,780,764 $5,895,693 $(5,027,082) $5,649,375104Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCondensed Consolidating Balance Sheet December 31, 2014 Parent/Issuer CombinedGuarantorSubsidiaries IntercompanyEliminations Consolidated (In thousands, except share data)ASSETS Current assets Cash and cash equivalents$776 $45,035 $— $45,811Accounts receivable – oil and gas revenues— 130,934 — 130,934Accounts receivable – joint interest and other— 175,537 — 175,537Accounts receivable – affiliates781 91,459 (92,240) —Inventory— 21,354 — 21,354Prepaid expenses297 13,976 — 14,273Derivative instruments— 302,159 — 302,159Other current assets— 6,539 — 6,539Total current assets1,854 786,993 (92,240) 696,607Property, plant and equipment Oil and gas properties (successful efforts method)— 5,966,140 — 5,966,140Other property and equipment— 313,439 — 313,439Less: accumulated depreciation, depletion, amortization andimpairment— (1,092,793) — (1,092,793)Total property, plant and equipment, net— 5,186,786 — 5,186,786Investments in and advances to subsidiaries4,032,494 — (4,032,494) —Derivative instruments— 13,348 — 13,348Deferred income taxes149,317 — (149,317) —Other assets99 12,236 — 12,335Total assets$4,183,764 $5,999,363 $(4,274,051) $5,909,076LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable$— $20,958 $— $20,958Accounts payable - affiliates91,459 781 (92,240) —Revenues and production taxes payable— 209,890 — 209,890Accrued liabilities— 410,379 — 410,379Accrued interest payable49,340 446 — 49,786Deferred income taxes— 97,499 — 97,499Advances from joint interest partners— 6,616 — 6,616Total current liabilities140,799 746,569 (92,240) 795,128Long-term debt2,170,664 500,000 — 2,670,664Deferred income taxes— 676,087 (149,317) 526,770Asset retirement obligations— 42,097 — 42,097Other liabilities— 2,116 — 2,116Total liabilities2,311,463 1,966,869 (241,557) 4,036,775Stockholders’ equity Capital contributions from affiliates— 2,899,203 (2,899,203) —Common stock, $0.01 par value: 300,000,000 shares authorized;101,627,296 shares issued and 101,341,619 shares outstanding1,001 — — 1,001Treasury stock, at cost: 285,677 shares(10,671) — — (10,671)Additional paid-in-capital1,007,202 8,743 (8,743) 1,007,202Retained earnings874,769 1,124,548 (1,124,548) 874,769Total stockholders’ equity1,872,301 4,032,494 (4,032,494) 1,872,301Total liabilities and stockholders’ equity$4,183,764 $5,999,363 $(4,274,051) $5,909,076105Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCondensed Consolidating Statement of Operations Year Ended December 31, 2015 Parent/Issuer CombinedGuarantorSubsidiaries IntercompanyEliminations Consolidated (In thousands)Revenues Oil and gas revenues$— $721,672 $— $721,672Well services and midstream revenues— 68,063 — 68,063Total revenues— 789,735 — 789,735Operating expenses Lease operating expenses— 144,481 — 144,481Well services and midstream operating expenses— 28,031 — 28,031Marketing, transportation and gathering expenses— 31,610 — 31,610Production taxes— 69,584 — 69,584Depreciation, depletion and amortization— 485,322 — 485,322Exploration expenses— 2,369 — 2,369Rig termination— 3,895 — 3,895Impairment of oil and gas properties— 46,109 — 46,109General and administrative expenses27,930 64,568 — 92,498Total operating expenses27,930 875,969 — 903,899Operating loss(27,930) (86,234) — (114,164)Other income (expense) Equity in earnings of subsidiaries69,986 — (69,986) —Net gain on derivative instruments— 210,376 — 210,376Interest expense, net of capitalized interest(138,166) (11,482) — (149,648)Other income (expense)5 (2,940) — (2,935)Total other income (expense)(68,175) 195,954 (69,986) 57,793Income (loss) before income taxes(96,105) 109,720 (69,986) (56,371)Income tax benefit (expense)55,857 (39,734) — 16,123Net income (loss)$(40,248) $69,986 $(69,986) $(40,248)106Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCondensed Consolidating Statement of Operations Year Ended December 31, 2014 Parent/Issuer CombinedGuarantorSubsidiaries IntercompanyEliminations Consolidated (In thousands)Revenues Oil and gas revenues$— $1,304,004 $— $1,304,004Well services and midstream revenues— 86,224 — 86,224Total revenues— 1,390,228 — 1,390,228Operating expenses Lease operating expenses— 169,600 — 169,600Well services and midstream operating expenses— 50,252 — 50,252Marketing, transportation and gathering expenses— 29,133 — 29,133Production taxes— 127,648 — 127,648Depreciation, depletion and amortization— 412,334 — 412,334Exploration expenses— 3,064 — 3,064Impairment of oil and gas properties— 47,238 — 47,238General and administrative expenses23,528 68,778 — 92,306Total operating expenses23,528 908,047 — 931,575Gain on sale of properties— 186,999 — 186,999Operating income (loss)(23,528) 669,180 — 645,652Other income (expense) Equity in earnings of subsidiaries613,601 — (613,601) —Net gain on derivative instruments— 327,011 — 327,011Interest expense, net of capitalized interest(147,230) (11,160) — (158,390)Other income (expense)5 190 — 195Total other income (expense)466,376 316,041 (613,601) 168,816Income before income taxes442,848 985,221 (613,601) 814,468Income tax benefit (expense)64,029 (371,620) — (307,591)Net income$506,877 $613,601 $(613,601) $506,877107Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCondensed Consolidating Statement of Operations Year Ended December 31, 2013 Parent/Issuer CombinedGuarantorSubsidiaries IntercompanyEliminations Consolidated (In thousands)Revenues Oil and gas revenues$— $1,084,412 $— $1,084,412Well services and midstream revenues— 57,587 — 57,587Total revenues— 1,141,999 — 1,141,999Operating expenses Lease operating expenses— 94,634 — 94,634Well services and midstream operating expenses— 30,713 — 30,713Marketing, transportation and gathering expenses— 25,924 — 25,924Production taxes— 100,537 — 100,537Depreciation, depletion and amortization— 307,055 — 307,055Exploration expenses— 2,260 — 2,260Impairment of oil and gas properties— 1,168 — 1,168General and administrative expenses14,044 61,266 — 75,310Total operating expenses14,044 623,557 — 637,601Operating income (loss)(14,044) 518,442 — 504,398Other income (expense) Equity in earnings of subsidiaries299,459 — (299,459) —Net loss on derivative instruments— (35,432) — (35,432)Interest expense, net of capitalized interest(99,663) (7,502) — (107,165)Other income (expense)(335) 1,551 — 1,216Total other income (expense)199,461 (41,383) (299,459) (141,381)Income before income taxes185,417 477,059 (299,459) 363,017Income tax benefit (expense)42,542 (177,600) — (135,058)Net income$227,959 $299,459 $(299,459) $227,959108Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCondensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 Parent/Issuer CombinedGuarantorSubsidiaries IntercompanyEliminations Consolidated (In thousands)Cash flows from operating activities: Net income (loss)$(40,248) $69,986 $(69,986) $(40,248)Adjustments to reconcile net income (loss) to net cash providedby operating activities: Equity in earnings of subsidiaries(69,986) — 69,986 —Depreciation, depletion and amortization— 485,322 — 485,322Impairment of oil and gas properties— 46,109 — 46,109Deferred income taxes(55,857) 39,743 — (16,114)Derivative instruments— (210,376) — (210,376)Stock-based compensation expenses24,762 510 — 25,272Deferred financing costs amortization and other4,964 7,335 — 12,299Working capital and other changes: Change in accounts receivable(482) (47,553) 156,496 108,461Change in inventory— 6,873 — 6,873Change in prepaid expenses19 1,809 — 1,828Change in other current assets— 6,489 — 6,489Change in other assets— (950) — (950)Change in accounts payable and accrued liabilities156,039 (71,160) (156,496) (71,617)Change in other current liabilities— 6,500 — 6,500Change in other liabilities and deferred credits— (33) — (33)Net cash provided by operating activities19,211 340,604 — 359,815Cash flows from investing activities: Capital expenditures— (819,847) — (819,847)Acquisition of oil and gas properties— (28,817) — (28,817)Proceeds from sale of properties— 1,075 — 1,075Derivative settlements— 370,410 — 370,410Advances from joint interest partners— (1,969) — (1,969)Net cash used in investing activities— (479,148) — (479,148)Cash flows from financing activities: Proceeds from revolving credit facility— 630,000 — 630,000Principal payments on revolving credit facility— (992,000) — (992,000)Deferred financing costs(11,045) (3,587) — (14,632)Proceeds from sale of common stock462,833 — — 462,833Purchases of treasury stock(2,949) — — (2,949)Investment in / capital contributions from subsidiaries(468,049) 468,049 — —Net cash provided by (used in) financing activities(19,210) 102,462 — 83,252Increase (decrease) in cash and cash equivalents1 (36,082) — (36,081)Cash and cash equivalents at beginning of period776 45,035 — 45,811Cash and cash equivalents at end of period$777 $8,953 $— $9,730109Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCondensed Consolidating Statement of Cash Flows Year Ended December 31, 2014 Parent/Issuer CombinedGuarantorSubsidiaries IntercompanyEliminations Consolidated (In thousands) Cash flows from operating activities: Net income$506,877 $613,601 $(613,601) $506,877Adjustments to reconcile net income to net cash provided by(used in) operating activities: Equity in earnings of subsidiaries(613,601) — 613,601 —Depreciation, depletion and amortization— 412,334 — 412,334Gain on sale of properties— (186,999) — (186,999)Impairment of oil and gas properties— 47,238 — 47,238Deferred income taxes(64,029) 371,486 — 307,457Derivative instruments— (327,011) — (327,011)Stock-based compensation expenses20,701 601 — 21,302Deferred financing costs amortization and other4,549 6,479 — 11,028Working capital and other changes: Change in accounts receivable(11) (65,657) 82,370 16,702Change in inventory— (3,776) — (3,776)Change in prepaid expenses21 (3,220) — (3,199)Change in other current assets— (6,135) — (6,135)Change in other assets— 114 — 114Change in accounts payable and accrued liabilities84,044 75,049 (82,370) 76,723Change in other liabilities— (139) — (139)Net cash provided by (used in) operating activities(61,449) 933,965 — 872,516Cash flows from investing activities: Capital expenditures— (1,354,281) — (1,354,281)Acquisition of oil and gas properties— (46,247) — (46,247)Proceeds from sale of properties— 324,852 — 324,852Costs related to sale of properties— (2,337) — (2,337)Derivative settlements— 6,774 — 6,774Advances from joint interest partners— (6,213) — (6,213)Net cash used in investing activities— (1,077,452) — (1,077,452)Cash flows from financing activities: Proceeds from revolving credit facility— 620,000 — 620,000Principal payments on revolving credit facility— (455,570) — (455,570)Deferred financing costs— (99) — (99)Purchases of treasury stock(5,309) — — (5,309)Investment in / capital contributions from subsidiaries33,433 (33,433) — —Other(176) — — (176)Net cash provided by financing activities27,948 130,898 — 158,846Decrease in cash and cash equivalents(33,501) (12,589) — (46,090)Cash and cash equivalents at beginning of period34,277 57,624 — 91,901Cash and cash equivalents at end of period$776 $45,035 $— $45,811110Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCondensed Consolidating Statement of Cash Flows Year Ended December 31, 2013 Parent/Issuer CombinedGuarantorSubsidiaries IntercompanyEliminations Consolidated (In thousands)Cash flows from operating activities: Net income$227,959 $299,459 $(299,459) $227,959Adjustments to reconcile net income to net cash provided by(used in) operating activities: Equity in earnings of subsidiaries(299,459) — 299,459 —Depreciation, depletion and amortization— 307,055 — 307,055Impairment of oil and gas properties— 1,168 — 1,168Deferred income taxes(42,542) 177,125 — 134,583Derivative instruments— 35,432 — 35,432Stock-based compensation expenses11,602 380 — 11,982Deferred financing costs amortization and other4,018 230 — 4,248Working capital and other changes: Change in accounts receivable(460) (110,266) 3,253 (107,473)Change in inventory— (13,941) — (13,941)Change in prepaid expenses(5) (8,186) — (8,191)Change in other current assets235 (291) — (56)Change in other assets— (3,248) — (3,248)Change in accounts payable and accrued liabilities20,710 89,994 (3,253) 107,451Change in other liabilities— 887 — 887Net cash provided by (used in) operating activities(77,942) 775,798 — 697,856Cash flows from investing activities: Capital expenditures— (893,524) — (893,524)Acquisition of oil and gas properties— (1,560,072) — (1,560,072)Derivative settlements— (8,133) — (8,133)Redemptions of short-term investments25,000 — — 25,000Advances from joint interest partners— (8,347) — (8,347)Net cash provided by (used in) investing activities25,000 (2,470,076) — (2,445,076)Cash flows from financing activities: Proceeds from issuance of senior notes1,000,000 — — 1,000,000Proceeds from revolving credit facility— 600,000 — 600,000Principal payments on revolving credit facility— (264,430) — (264,430)Deferred financing costs(16,362) (6,548) — (22,910)Proceeds from sale of common stock314,580 — — 314,580Purchases of treasury stock(1,566) — — (1,566)Investment in / capital contributions from subsidiaries(1,343,230) 1,343,230 — —Net cash provided by (used in) financing activities(46,578) 1,672,252 — 1,625,674Decrease in cash and cash equivalents(99,520) (22,026) — (121,546)Cash and cash equivalents at beginning of period133,797 79,650 — 213,447Cash and cash equivalents at end of period$34,277 $57,624 $— $91,901111Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents20. Supplemental Oil and Gas DisclosuresThe supplemental data presented below reflects information for all of the Company’s oil and natural gas producing activities.Capitalized CostsThe following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities at December 31, 2015 and2014: December 31, 2015(1) 2014 (In thousands)Proved oil and gas properties(2)$5,655,759 $5,156,875Less: Accumulated depreciation, depletion, amortization and impairment(1,428,427) (1,043,121)Proved oil and gas properties, net4,227,332 4,113,754Unproved oil and gas properties628,642 809,265Total oil and gas properties, net$4,855,974 $4,923,019__________________ (1)At December 31, 2015, oil and gas properties exclude capitalized costs related to certain non-core assets that were held for sale (see Note 7 — AssetsHeld for Sale).(2)Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $30.7 million and $36.9 million atDecember 31, 2015 and 2014, respectively.Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development ActivitiesThe following table sets forth costs incurred related to the Company’s oil and natural gas activities for the years ended December 31, 2015, 2014 and2013: Year Ended December 31, 2015 2014 2013 (In thousands)Acquisition costs: Proved oil and gas properties$28,737 $37,048 $752,454Unproved oil and gas properties3,226 30,891 837,419Exploration costs2,369 3,064 2,260Development costs433,735 1,437,923 890,267Asset retirement costs1,474 6,278 11,856Total costs incurred$469,541 $1,515,204 $2,494,256Results of Operations for Oil and Natural Gas Producing ActivitiesResults of operations for oil and natural gas producing activities, which excludes straight-line depreciation, general and administrative expenses andinterest expense, are presented below. 112Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents Year Ended December 31, 2015 2014 2013 (In thousands)Revenues$721,672 $1,304,004 $1,084,412Production costs245,675 326,381 221,095Depreciation, depletion and amortization472,800 400,118 298,999Exploration costs2,369 3,064 2,260Rig termination3,895 — —Impairment of oil and gas properties46,109 47,238 1,168Income tax expense (benefit)(18,382) 197,701 196,312Results of operations for oil and natural gas producing activities$(30,794) $329,502 $364,578113Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents21. Supplemental Oil and Gas Reserve Information — UnauditedThe reserve estimates at December 31, 2015, 2014 and 2013 presented in the table below are based on reports prepared by DeGolyer andMacNaughton, the Company’s independent reserve engineers, in accordance with the FASB’s authoritative guidance on oil and gas reserve estimation anddisclosures. At December 31, 2015, 2014 and 2013, all of the Company’s oil and natural gas producing activities were conducted within the continentalUnited States.The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are moreimprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as futureinformation becomes available.Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data demonstrate, withreasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at thetime the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells andequipment in place and under operating methods being utilized at the time the estimates were made.Estimated Quantities of Proved Oil and Natural Gas Reserves — UnauditedThe following table sets forth the Company’s estimated net proved, proved developed and proved undeveloped reserves at December 31, 2015,2014 and 2013: 114Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents Oil(MBbl) Gas(MMcf) MBoe2013 Proved reserves Beginning balance128,090 91,530 143,345Revisions of previous estimates3,390 10,412 5,125Extensions, discoveries and other additions40,784 31,856 46,094Sales of reserves in place— — —Purchases of reserves in place37,459 49,631 45,731Production(11,133) (7,450) (12,375)Net proved reserves at December 31, 2013198,590 175,979 227,920Proved developed reserves, December 31, 2013106,774 92,170 122,136Proved undeveloped reserves, December 31, 201391,816 83,809 105,7842014 Proved reserves Beginning balance198,590 175,979 227,920Revisions of previous estimates(23,069) (12,290) (25,117)Extensions, discoveries and other additions80,855 70,449 92,596Sales of reserves in place(7,640) (4,850) (8,448)Purchases of reserves in place1,546 1,523 1,799Production(14,883) (10,691) (16,664)Net proved reserves at December 31, 2014235,399 220,120 272,086Proved developed reserves, December 31, 2014127,340 114,016 146,343Proved undeveloped reserves, December 31, 2014108,059 106,104 125,7432015 Proved reserves Beginning balance235,399 220,120 272,086Revisions of previous estimates(75,458) (55,065) (84,635)Extensions, discoveries and other additions38,962 46,072 46,640Sales of reserves in place— — —Purchases of reserves in place2,115 2,702 2,565Production(16,090) (14,001) (18,423)Net proved reserves at December 31, 2015184,928 199,828 218,233Proved developed reserves, December 31, 2015127,445 120,789 147,577Proved undeveloped reserves, December 31, 201557,483 79,039 70,656Revisions of Previous EstimatesIn 2015, the Company had a net negative revision of 84,635 MBoe, or 31% of the beginning of the year estimated net proved reserves balance.This net negative revision was primarily due to the removal of proved undeveloped reserves that are not economic at the lower oil price or are no longeraligned with the Company’s anticipated five-year drilling plan. This resulted in 259 gross (190.8 net) proved undeveloped locations with 71,945 MBoe ofreserves being removed from the December 31, 2015 estimated net proved reserves balance, most significantly, removing proved undeveloped reservesoutside of the Company’s core acreage within the Williston Basin that were uneconomic as of December 31, 2015 due to the lower oil price. The remainingnegative revision is primarily attributable to the impact of price on producing life, partially offset by positive revisions due to performance and operatingcosts.In 2014, the Company had a net negative revision of 25,117 MBoe, or 11% of the beginning of the year estimated net proved reserves balance.This net negative revision was primarily due to the removal of proved undeveloped reserves not aligned with the Company’s anticipated five-year drillingplan, which was adjusted to allocate a greater focus on higher rates-of-return areas of the Bakken and Three Forks formations. This resulted in 80 gross (56.2net) proved undeveloped locations with 21,411 MBoe of reserves being removed from the December 31, 2014 estimated net proved reserves balance.115Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIn 2013, the Company had a net positive revision of 5,125 MBoe, or 4% of the beginning of the year estimated net proved reserves balance. Thisnet positive revision was the result of several immaterial changes, including well performances, working interests, operating costs and realized prices.Extensions, Discoveries and Other AdditionsIn 2015, the Company had a total of 46,640 MBoe of additions due to extensions and discoveries. An estimated 20,362 MBoe of theseextensions and discoveries were associated with new producing wells at December 31, 2015, with 100% of these reserves from wells producing in the Bakkenor Three Forks formations. An additional 26,278 MBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s2015 operated and non-operated drilling program and anticipated five-year drilling plan, with 100% of these proved undeveloped reserves in the Bakken orThree Forks formations.In 2014, the Company had a total of 92,596 MBoe of additions due to extensions and discoveries. An estimated 34,404 MBoe of theseextensions and discoveries were associated with new producing wells at December 31, 2014, with 100% of these reserves from wells producing in the Bakkenor Three Forks formations. An additional 58,192 MBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s2014 operated and non-operated drilling program and anticipated five-year drilling plan, with 100% of these proved undeveloped reserves in the Bakken orThree Forks formations.In 2013, the Company had a total of 46,094 MBoe of additions due to extensions and discoveries. An estimated 22,190 MBoe of theseextensions and discoveries were associated with new producing wells at December 31, 2013, with 100% of these reserves from wells producing in the Bakkenor Three Forks formations. An additional 23,904 MBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s2013 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.Sales of Reserves in Place In March 2014, the Company divested 8,448 MBoe of reserves associated with its non-operated properties sold in the Sanish Divestiture. In 2015and 2013, the Company did not have any sales of reserves.Purchases of Reserves in Place In 2015 and 2014, the Company purchased estimated net proved reserves of 2,565 MBoe and 1,799 MBoe, respectively, from acquisitions ofadditional working interests in its existing properties in the Williston Basin. In 2013, the Company purchased 45,731 MBoe of estimated net proved reservesfrom properties acquired in the 2013 Acquisitions (see Note 6 — Acquisitions and Divestitures).Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — UnauditedThe Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves,less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of futurecash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs.The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices foroil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmeticaverage first-day-of-the-month prices for the prior twelve months were $50.16/Bbl for oil and $2.63/MMBtu for natural gas, $95.28/Bbl for oil and$4.35/MMBtu for natural gas and $96.96/Bbl for oil and $3.66/MMBtu for natural gas for the years ended December 31, 2015, 2014 and 2013, respectively.These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affectingthe price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs as of each year-end.The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’sestimated net proved reserves at December 31, 2015, 2014 and 2013: 116Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents At December 31, 2015 2014 2013 (In thousands)Future cash inflows$8,582,831 $21,656,832 $19,063,500Future production costs(3,842,517) (7,094,426) (5,473,767)Future development costs(909,562) (2,563,062) (1,904,095)Future income tax expense(225,662) (3,188,389) (3,628,977)Future net cash flows3,605,090 8,810,955 8,056,66110% annual discount for estimated timing of cash flows(1,690,760) (4,829,294) (4,329,102)Standardized measure of discounted future net cash flows$1,914,330 $3,981,661 $3,727,559The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net provedreserves for the periods presented: 2015 2014 2013 (In thousands)January 1$3,981,661 $3,727,559 $2,259,897Net changes in prices and production costs(3,201,195) (588,212) 254,979Net changes in future development costs150,333 (61,760) 57,566Sales of oil and natural gas, net(477,755) (979,938) (857,540)Extensions409,838 1,751,007 1,111,202Discoveries— — —Purchases of reserves in place14,378 38,035 858,382Sales of reserves in place— (251,002) —Revisions of previous quantity estimates(946,729) (604,651) 99,954Previously estimated development costs incurred216,981 249,926 373,912Accretion of discount548,141 548,690 346,068Net change in income taxes1,391,358 259,592 (774,910)Changes in timing and other(172,681) (107,585) (1,951)December 31$1,914,330 $3,981,661 $3,727,559117Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents22. Quarterly Financial Data — UnauditedThe Company’s results of operations by quarter for the years ended December 31, 2015 and 2014 are as follows: For the Year Ended December 31, 2015 FirstQuarter SecondQuarter ThirdQuarter FourthQuarter (In thousands)Revenues$180,387 $230,046 $197,235 $182,067Operating loss(33,635) (7,437) (19,926) (53,166)Net income (loss)(18,041) (53,230) 27,055 3,968 For the Year Ended December 31, 2014 FirstQuarter SecondQuarter ThirdQuarter FourthQuarter (In thousands)Revenues$349,519 $372,378 $368,659 $299,672Operating income329,080 166,545 134,103 15,924Net income169,953 38,833 121,587 176,504Item 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureNone.Item 9A. Controls and ProceduresEvaluation of disclosure controls and procedures. As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the“Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”),our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, the effectiveness of the design and operation of ourdisclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2015. Our disclosure controlsand procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under theExchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information isaccumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure.Based on the evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective at December 31, 2015 at thereasonable assurance level.Management’s report on internal control over financial reporting. Management, including our CEO and CFO, is responsible for establishingand maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internalcontrol over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation ofour financial statements for external purposes in accordance with generally accepted accounting principles.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degreeof compliance with the policies or procedures may deteriorate.As of December 31, 2015, management assessed the effectiveness of our internal control over financial reporting. In making this assessment,management, including our CEO and CFO, used the criteria set forth by the Internal Control — Integrated Framework (2013) issued by the Committee ofSponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, management concluded that our internal control over financialreporting was effective as of December 31, 2015.PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our consolidated financial statements included inthis annual report on Form 10-K, has also audited the effectiveness of our internal control over financial reporting at December 31, 2015. Their “Report ofIndependent Registered Public Accounting Firm,” which expresses118Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsan unqualified opinion on the effectiveness of our internal control over financial reporting at December 31, 2015, is included in Item 8.Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2015 that have materially affected, or arereasonably likely to materially affect, our internal control over financial reporting.Item 9B. Other InformationNone.119Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPART IIIItem 10. Directors, Executive Officers and Corporate GovernancePursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitiveproxy statement for our 2016 Annual Meeting of Stockholders.Item 11. Executive CompensationPursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitiveproxy statement for our 2016 Annual Meeting of Stockholders.Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder MattersPursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitiveproxy statement for our 2016 Annual Meeting of Stockholders.Item 13. Certain Relationships and Related Transactions and Director IndependencePursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitiveproxy statement for our 2016 Annual Meeting of Stockholders.Item 14. Principal Accountant Fees and ServicesPursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitiveproxy statement for our 2016 Annual Meeting of Stockholders.120Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPART IVItem 15. Exhibits, Financial Statement Schedulesa. The following documents are filed as a part of this Annual Report on Form 10-K or incorporated herein by reference:(1)Financial Statements:See Item 8. Financial Statements and Supplementary Data.(2)Financial Statement Schedules:None.(3)Exhibits:The following documents are included as exhibits to this report:Exhibit No.Description of Exhibit3.1Amended and Restated Certificate of Incorporation of Oasis Petroleum Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form8-K on June 24, 2010, and incorporated herein by reference). 3.2Amended and Restated Bylaws of Oasis Petroleum Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K on June 24,2010, and incorporated herein by reference). 4.1Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on May 19, 2010, andincorporated herein by reference). 4.2Registration Rights Agreement dated as of September 24, 2013 among the Company, the Guarantors and Wells Fargo Securities, LLC, asrepresentative of the several initial purchasers (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on September 25, 2013,and incorporated herein by reference). 4.3Indenture dated as of February 2, 2011 among the Company and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to theCompany’s Current Report on Form 8-K on February 2, 2011, and incorporated herein by reference). 4.4First Supplemental Indenture dated as of February 2, 2011 among the Company, the Guarantors and U.S. Bank National Association, astrustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on February 2, 2011, and incorporated herein by reference). 4.5Second Supplemental Indenture dated as of September 19, 2011 among the Company, the Guarantors and U.S. Bank NationalAssociation, as trustee (filed as Exhibit 4.4 to the Company’s Registration Statement on Form S-4 on September 23, 2011, andincorporated herein by reference). 4.6Indenture dated as of November 10, 2011 among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed asExhibit 4.1 to the Company’s Current Report on Form 8-K on November 10, 2011, and incorporated herein by reference). 4.7First Supplemental Indenture dated as of November 10, 2011 among the Company, the Guarantors and U.S. Bank National Association, astrustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on November 10, 2011, and incorporated herein by reference). 4.8Second Supplemental Indenture dated as of July 2, 2012 among the Company, the Guarantors and U.S. Bank National Association, astrustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on July 2, 2012, and incorporated herein by reference). 4.9Third Supplemental Indenture (to the Indenture dated as of February 2, 2011) dated as of June 18, 2013 among the Company, theGuarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q onAugust 7, 2013, and incorporated herein by reference). 4.10Third Supplemental Indenture (to the Indenture dated as of November 10, 2011) dated as of June 18, 2013 among the Company, theGuarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q onAugust 7, 2013, and incorporated herein by reference). 4.11Fourth Supplemental Indenture dated as of September 24, 2013 among the Company, the Guarantors and U.S. Bank National Association,as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on September 25, 2013, and incorporated herein byreference). 4.12Fifth Supplemental Indenture (to the Indenture dated as of February 2, 2011) dated as of October 26, 2015 among the Company, theGuarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed onOctober 30, 2015, and incorporated herein by reference). 121Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No.Description of Exhibit4.13Fourth Supplemental Indenture (to the Indenture dated as of November 10, 2011) dated as of October 26, 2015 among the Company, theGuarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed onOctober 30, 2015, and incorporated herein by reference). 4.14Fifth Supplemental Indenture (to the Indenture dated as of November 10, 2011) dated as of October 26, 2015 among the Company, theGuarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K filed onOctober 30, 2015, and incorporated herein by reference). 10.1Business Opportunities Agreement dated as of June 22, 2010 by and among Oasis Petroleum Inc., EnCap Investments L.P., Douglas E.Swanson, Jr. and Robert L. Zorich (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on June 24, 2010, andincorporated herein by reference). 10.2Second Amended and Restated Credit Agreement, dated as of April 5, 2013, among Oasis Petroleum Inc., as parent, Oasis Petroleum NorthAmerica LLC, as borrower, the other credit parties party thereto, Wells Fargo Bank, N.A., as administrative agent and the lenders partythereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 9, 2013, and incorporated herein by reference). 10.3First Amendment to Second Amended and Restated Credit Agreement dated as of September 3, 2013 among Oasis Petroleum Inc., asParent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties thereto, Wells Fargo Bank, N.A., as AdministrativeAgent and the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 5, 2013, andincorporated herein by reference). 10.4**Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed as Exhibit 10.1 to the Company’s Quarterly Reporton Form 10-Q on August 6, 2014, and incorporated herein by reference). 10.5**Form of Indemnification Agreement between Oasis Petroleum Inc. and each of the directors and executive officers thereof (filed as Exhibit10.5 to the Company’s Annual Report on Form 10-K on February 25, 2015, and incorporated herein by reference). 10.6**Amended and Restated 2010 Annual Incentive Compensation Plan of Oasis Petroleum Inc. (filed as Exhibit 10.2 to the Company’sQuarterly Report on Form 10-Q on August 6, 2014, and incorporated herein by reference). 10.7**Form of Notice of Grant of Restricted Stock (filed as Exhibit 10.10 to the Company’s Registration Statement on Form S-1/A on May 19,2010, and incorporated herein by reference). 10.8**Form of Restricted Stock Agreement (filed as Exhibit 10.11 to the Company’s Registration Statement on Form S-1/A on May 19, 2010,and incorporated herein by reference). 10.9**Form of Notice of Grant of Restricted Stock Unit (filed as Exhibit 10.12 to the Company’s Registration Statement on Form S-1/A on May19, 2010, and incorporated herein by reference). 10.10**Form of Notice of Grant of Restricted Stock Unit Designated as a Performance Share Unit (filed as Exhibit 10.13 to the Company’sRegistration Statement on Form S-1/A on May 19, 2010, and incorporated herein by reference). 10.11**Form of Restricted Stock Unit Agreement (filed as Exhibit 10.14 to the Company’s Registration Statement on Form S-1/A on May 19,2010, and incorporated herein by reference). 10.12**Form of Notice of Grant of Performance Share Units (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on August 3,2012, and incorporated herein by reference). 10.13**Form of Performance Share Unit Agreement (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on August 3, 2012, andincorporated herein by reference). 10.14**April 20, 2012 Resignation, Consent and Appointment Agreement and Amendment Agreement (filed as Exhibit 10.1 to the Company’sCurrent Report on Form 8-K on April 23, 2012, and incorporated herein by reference). 10.15**Amended and Restated Employment Agreement dated as of March 1, 2012 between Oasis Petroleum Inc. and Thomas B. Nusz (filed asExhibit 10.1 to the Company’s Current Report on Form 8-K on March 2, 2012, and incorporated herein by reference). 10.16**Employment Agreement dated as of March 1, 2012 between Oasis Petroleum Inc. and Michael H. Lou (filed as Exhibit 10.3 to theCompany’s Current Report on Form 8-K on March 2, 2012, and incorporated herein by reference). 122Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No.Description of Exhibit10.17**Second Amended and Restated Employment Agreement dated as of December 23, 2013 between Oasis Petroleum Inc. and Taylor L. Reid(filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on December 24, 2013, and incorporated herein by reference). 10.18**Employment Agreement dated as of December 23, 2013 between Oasis Petroleum Inc. and Nickolas J. Lorentzatos (filed as Exhibit 10.2to the Company’s Current Report on Form 8-K on December 24, 2013, and incorporated herein by reference). 10.19**Second Amended and Restated Employment Agreement effective as of March 1, 2015 between Oasis Petroleum Inc. and Thomas B. Nusz(filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 30, 2015, and incorporated herein by reference). 10.20**Third Amended and Restated Employment Agreement effective as of March 1, 2015 between Oasis Petroleum Inc. and Taylor L. Reid(filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on January 30, 2015, and incorporated herein by reference). 10.21**Amended and Restated Employment Agreement effective as of March 1, 2015 between Oasis Petroleum Inc. and Michael H. Lou (filed asExhibit 10.3 to the Company’s Current Report on Form 8-K on January 30, 2015, and incorporated herein by reference). 10.22**Amended and Restated Employment Agreement effective as of March 1, 2015 between Oasis Petroleum Inc. and Nickolas J. Lorentzatos(filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on January 30, 2015, and incorporated herein by reference). 10.23**Amended and Restated Executive Change in Control and Severance Benefit Plan dated as of March 1, 2012 (filed as Exhibit 10.4 to theCompany’s Current Report on Form 8-K on March 2, 2012, and incorporated herein by reference). 10.24Purchase and Sale Agreement, dated September 4, 2013, by and among Oasis Petroleum North America LLC and two undisclosed privatesellers (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on September 5, 2013, and incorporated herein by reference). 10.25Purchase Agreement dated as of September 10, 2013 among the Company, the Guarantors and Wells Fargo Securities, LLC, asrepresentative of the several initial purchasers (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 11,2013, and incorporated herein by reference). 10.26Second Amendment to Second Amended and Restated Credit Agreement dated as of September 30, 2014 among Oasis Petroleum Inc., asParent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties thereto, Wells Fargo Bank, N.A., as AdministrativeAgent and the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on October 2, 2014, andincorporated herein by reference). 10.27Letter Agreement dated as of March 4, 2015 between the Company and SPO Advisory Corp. (filed as Exhibit 10.1 to the Company’sCurrent Report on Form 8-K on March 9, 2015, and incorporated herein by reference). 10.28**Third Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis Petroleum Inc. and Thomas B. Nusz(filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 20, 2015, and incorporated herein by reference). 10.29**Fourth Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis Petroleum Inc. and Taylor L. Reid(filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 20, 2015, and incorporated herein by reference). 10.30**Second Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis Petroleum Inc. and Michael H. Lou(filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on March 20, 2015, and incorporated herein by reference). 10.31**Second Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis Petroleum Inc. and Nickolas J.Lorentzatos (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on March 20, 2015, and incorporated herein byreference). 10.32Third Amendment to Second Amended and Restated Credit Agreement dated as of April 13, 2015 among Oasis Petroleum Inc., as Parent,Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties party thereto, Wells Fargo Bank, N.A., as Administrative Agent,and the Lenders party thereto (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on April 14, 2015, and incorporatedherein by reference). 123Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No.Description of Exhibit10.33Fourth Amendment to Second Amended and Restated Credit Agreement dated as of November 13, 2015 among Oasis Petroleum Inc., asParent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties party thereto, Wells Fargo Bank, N.A., asAdministrative Agent and the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on November18, 2015, and incorporated herein by reference). 10.34**First Amendment to the Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed as Exhibit 10.1 to theCompany’s Current Report on Form 8-K on May 6, 2015 and incorporated herein by reference). 10.35(a)Fifth Amendment to Second Amended and Restated Credit Agreement dated as of February 23, 2016 among Oasis Petroleum Inc., asParent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties party thereto, Wells Fargo Bank, N.A., asAdministrative Agent and the Lenders party thereto. 12.1(a)Computation of Ratio of Earnings to Fixed Charges. 21.1(a)List of Subsidiaries of Oasis Petroleum Inc. 23.1(a)Consent of PricewaterhouseCoopers LLP. 23.2(a)Consent of DeGolyer and MacNaughton. 31.1(a)Sarbanes-Oxley Section 302 certification of Principal Executive Officer. 31.2(a)Sarbanes-Oxley Section 302 certification of Principal Financial Officer. 32.1(b)Sarbanes-Oxley Section 906 certification of Principal Executive Officer. 32.2(b)Sarbanes-Oxley Section 906 certification of Principal Financial Officer. 99.1Report of DeGolyer and MacNaughton (filed as Exhibit 99.2 to the Company’s Current Report on Form 8-K on January 28, 2016 andincorporated herein by reference). 101.INS(a)XBRL Instance Document. 101.SCH(a)XBRL Schema Document. 101.CAL(a)XBRL Calculation Linkbase Document. 101.DEF(a)XBRL Definition Linkbase Document. 101.LAB(a)XBRL Labels Linkbase Document. 101.PRE(a)XBRL Presentation Linkbase Document.__________________ (a)Filed herewith.(b)Furnished herewith.**Management contract or compensatory plan or arrangement.124Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signedon its behalf by the undersigned thereunto duly authorized, on February 25, 2016. OASIS PETROLEUM INC. By: /s/ Thomas B. Nusz Thomas B. NuszChairman of the Board and Chief Executive OfficerPursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of theregistrant and in the capacity and on the dates indicated: Signature Title Date /s/ Thomas B. Nusz Chairman of the Board and Chief Executive Officer(Principal Executive Officer) February 25, 2016Thomas B. Nusz /s/ Taylor L. Reid Director, President and Chief Operating Officer February 25, 2016Taylor L. Reid /s/ Michael H. Lou Executive Vice President and Chief Financial Officer(Principal Financial Officer and Principal Accounting Officer) February 25, 2016Michael H. Lou /s/ William J. Cassidy Director February 25, 2016William J. Cassidy /s/ Ted Collins, Jr. Director February 25, 2016Ted Collins, Jr. /s/ Michael McShane Director February 25, 2016Michael McShane /s/ Bobby S. Shackouls Director February 25, 2016Bobby S. Shackouls /s/ Douglas E. Swanson, Jr. Director February 25, 2016Douglas E. Swanson, Jr. 125Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGLOSSARY OF OIL AND NATURAL GAS TERMSThe terms defined in this section are used throughout this Annual Report on Form 10-K:“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.“Bcf.” One billion cubic feet of natural gas.“Boe.” Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.“British thermal unit.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil,or in the case of a dry hole, the reporting of abandonment to the appropriate agency.“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.“Developed reserves.” Reserves of any category that can be expected to be recovered through existing wells with existing equipment andoperating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well.“Development well.” A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to beproductive.“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such productionexceed production expenses and taxes.“Economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.“Environmental assessment.” An environmental assessment, a study that can be required pursuant to federal law to assess the potential direct,indirect and cumulative impacts of a project.“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a fieldpreviously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structuralfeature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productiveformations.“Formation.” A layer of rock which has distinct characteristics that differ from nearby rock.“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at aright angle within a specified interval.“Infill wells.” Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through theformation.“MBbl.” One thousand barrels of crude oil, condensate or natural gas liquids.“MBoe.” One thousand barrels of oil equivalent.“Mcf.” One thousand cubic feet of natural gas.“MMBbl.” One million barrels of crude oil, condensate or natural gas liquids.“MMBoe.” One million barrels of oil equivalent.126Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents“MMBtu.” One million British thermal units.“MMcf.” One million cubic feet of natural gas.“NYMEX.” The New York Mercantile Exchange.“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in100 acres owns 50 net acres.“PV-10.” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from theproduction of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at thedetermination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discountrate of 10% in accordance with the guidelines of the Commission.“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of theproduction exceed production expenses and taxes.“Proved developed reserves.” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operatingmethods.“Proved reserves.” Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonablecertainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods,and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonablycertain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must havecommenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered asproved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, withreasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience andengineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in awell penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Wheredirect observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oilreserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technologyestablish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques(including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoirwith properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or otherevidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) theproject has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions includeprices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period priorto the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each monthwithin such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.“Proved undeveloped reserves.” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wellswhere a relatively major expenditure is required for recompletion.“Reasonable certainty.” A high degree of confidence.“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in anattempt to establish or increase existing production.“Reserves.” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a givendate by application of development prospects to known accumulations.“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that isconfined by impermeable rock or water barriers and is separate from other reservoirs.“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, andis often established by regulatory agencies.127Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operationwithout regard to separate property interests. Also, the area covered by a unitization agreement.“Wellbore.” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The workinginterest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.“Workover.” The repair or stimulation of an existing productive well for the purpose of restoring, prolonging or enhancing the production ofhydrocarbons.128Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Executed VersionFIFTH AMENDMENTTOSECOND AMENDED AND RESTATED CREDIT AGREEMENTDated as of February 23, 2016AMONGOASIS PETROLEUM NORTH AMERICA LLC,AS BORROWER,THE GUARANTORS PARTY HERETO,WELLS FARGO BANK, N.A.,AS ADMINISTRATIVE AGENT,ANDTHE LENDERS PARTY HERETOSource: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.FIFTH AMENDMENT TOSECOND AMENDED AND RESTATED CREDIT AGREEMENTTHIS FIFTH AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT (this “FifthAmendment”) dated as of February 23, 2016, is among OASIS PETROLEUM NORTH AMERICA LLC, a Delaware limitedliability company (the “Borrower”); the Guarantors party hereto (the “Guarantors” and collectively with the Borrower, the “CreditParties”); each of the lenders party to the Credit Agreement referred to below (collectively, the “Lenders”) party hereto; and WELLSFARGO BANK, N.A., as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the“Administrative Agent”) and as the issuing bank (in such capacity, the “Issuing Bank”).R E C I T A L SA. Parent, OP LLC, the Borrower, the Administrative Agent and the Lenders are parties to that certain Second Amended andRestated Credit Agreement dated as of April 5, 2013, as amended by that certain First Amendment to Second Amended and RestatedCredit Agreement dated as of September 3, 2013, that certain Second Amendment to Second Amended and Restated CreditAgreement dated as of September 30, 2014, that certain Third Amendment to Second Amended and Restated Credit Agreement datedas of April 13, 2015 and that certain Fourth Amendment to Second Amended and Restated Credit Agreement dated as of November13, 2015 (the “Credit Agreement”), pursuant to which the Lenders have made certain credit available to and on behalf of theBorrower.B. The Borrower, the Guarantors, the Administrative Agent and the Lenders party hereto desire to amend certain provisionsof the Credit Agreement as set forth herein including providing for a reduction of the Aggregate Elected Commitment Amounts to$1,150,000,000 effective as of the Fifth Amendment Effective Date (as defined below).C. The Lenders desire to provide for the April 1, 2016 Scheduled Redetermination, pursuant to which the Borrowing Basewill be reduced to $1,150,000,000 effective as of the Fifth Amendment Effective Date.NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuableconsideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:Section 1.Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning givensuch term in the Credit Agreement, as amended by this Fifth Amendment. Unless otherwise indicated, all section references in thisFifth Amendment refer to sections of the Credit Agreement.Section 2. Amendments to Credit Agreement.2.1 Amendments to Section 1.02.(a) The following definition is hereby amended and restated as follows:1Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.“Agreement” means this Second Amended and Restated Credit Agreement, as amended by the First Amendment, theSecond Amendment, the Third Amendment, the Fourth Amendment and the Fifth Amendment and as the same may be furtheramended or supplemented from time to time.(b) The following definitions are hereby added where alphabetically appropriate to read as follows:“Fifth Amendment” means that certain Fifth Amendment to Second Amended and Restated Credit Agreement, dated asof February 23, 2016, among the Borrower, the Guarantors, the Administrative Agent and the Lenders party thereto.“Specified Redemption Test” means, at the time of determination, with respect to any event in connection with whichsuch determination is made, each of the following conditions is satisfied: (a) no Default, Event of Default or Borrowing BaseDeficiency has occurred and is continuing or would result from such event, (b) the amount of the undrawn Commitments aftergiving effect to such event shall represent at least 50% of the aggregate Commitments at such time and (c) the Borrower is ableto satisfy each of the conditions contained in Section 6.02 at the time of determination.2.2 Amendment to Section 2.06(c). Section 2.06(c) is hereby amended by adding the following as the new Section 2.06(c)(viii) and the new Section 2.06(c)(ix) at the end thereof:(viii) Upon any redetermination or other adjustment in the Borrowing Base pursuant to this Agreement that wouldotherwise result in the Borrowing Base becoming less than the Aggregate Elected Commitment Amounts, the AggregateElected Commitment Amounts shall be automatically reduced (ratably among the Lenders in accordance with each Lender’sApplicable Percentage) so that they equal such redetermined Borrowing Base (and Annex I shall be deemed amended to reflectsuch amendments to each Lender’s Elected Commitment and the Aggregate Elected Commitment Amounts).(ix) Contemporaneously with any increase in the Borrowing Base pursuant to this Agreement, if (A) the Borrowerelects to increase the Aggregate Elected Commitment Amount and (B) each Lender has consented to such increase in itsElected Commitment, then the Aggregate Elected Commitment Amount shall be increased (ratably among the Lenders inaccordance with each Lender’s Applicable Percentage) by the amount requested by the Borrower (subject to the limitations setforth in Section 2.06(c)(ii)(A)) without the requirement that any Lender deliver an Elected Commitment Increase Certificate,and Annex I shall be deemed amended to reflect such amendments to each Lender’s Elected Commitment and the AggregateElected Commitment Amount. The Administrative Agent shall record the information regarding such increases in the Registerrequired to be maintained by the Administrative Agent pursuant to Section 12.04(b)(iv).2Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.2.3 Amendment to Section 2.08(j). Section 2.08(j) of the Credit Agreement is hereby amended by inserting “or Section3.04(e)” after each reference to “Section 3.04(c)”.2.4 Amendment to Section 3.04. Section 3.04 is hereby amended by adding the following as the new Section 3.04(e) at theend thereof:(e) Excess Cash Balances. If at any time while there are any Borrowings outstanding, the Borrower or any otherCredit Party have any cash or cash equivalents (other than cash collateral) in excess of $50,000,000 in the aggregate at any time(other than (i) any cash set aside to pay royalty obligations of the Credit Parties then due and owing to unaffiliated third partiesand for which the Credit Parties have issued checks or have initiated wires or ACH transfers (or will issue checks or initiatewires or ACH transfers within one Business Day) in order to pay, (ii) any cash set aside to pay in the ordinary course ofbusiness amounts (other than royalty obligations) of the Credit Parties then due and owing to unaffiliated third parties and forwhich the Credit Parties have issued checks or have initiated wires or ACH transfers in order to pay and (iii) any cash of theCredit Parties constituting purchase price deposits held in escrow by an unaffiliated third party pursuant to a binding andenforceable purchase and sale agreement with an unaffiliated third party containing customary provisions regarding thepayment and refunding of such deposits) (the “Excess Cash”), then the Borrower shall prepay the Borrowings in an amountequal to the Excess Cash; provided that to the extent that any Excess Cash results from the receipt of the proceeds of any saleor disposition of Property, then the Borrower shall not be required to prepay such Excess Cash until the fifth Business Dayfollowing the receipt of such proceeds. Each prepayment of Borrowings pursuant to this Section 3.04(e) shall be applied asdirected by the Borrower, provided that if the Borrower does not provide instructions for the application of such prepayment,such prepayment shall be applied, first, ratably to any ABR Borrowings then outstanding, and, second, to any EurodollarBorrowings then outstanding, and if more than one Eurodollar Borrowing is then outstanding, to each such EurodollarBorrowing in order of priority beginning with the Eurodollar Borrowing with the least number of days remaining in the InterestPeriod applicable thereto and ending with the Eurodollar Borrowing with the most number of days remaining in the InterestPeriod applicable thereto. Each prepayment of Borrowings pursuant to this Section 3.04(e) shall be applied ratably to the Loansincluded in the prepaid Borrowings. Prepayments pursuant to this Section 3.04(e) shall be accompanied by accrued interest tothe extent required by Section 3.02.2.5 Amendments to Section 6.02.(a) Section 6.02 of the Credit Agreement is hereby amended by inserting the following as the new clause (f) at the endthereof:3Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(f) At the time of and immediately after giving effect to such Borrowing or the issuance, amendment, renewal orextension of such Letter of Credit, as applicable, the Borrower together with the other Credit Parties shall not have any cash orcash equivalents (other than cash collateral) in excess of $50,000,000 in the aggregate (other than (i) any cash set aside to payroyalty obligations of the Credit Parties then due and owing to unaffiliated third parties and for which the Credit Parties haveissued checks or have initiated wires or ACH transfers (or will issue checks or initiate wires or ACH transfers within 24 hoursof such time) in order to pay, (ii) any cash set aside to pay in the ordinary course of business amounts (other than royaltyobligations) of the Credit Parties then due and owing to unaffiliated third parties and for which the Credit Parties have issuedchecks or have initiated wires or ACH transfers in order to pay and (iii) any cash of the Credit Parties constituting purchaseprice deposits held in escrow by an unaffiliated third party pursuant to a binding and enforceable purchase and sale agreementwith an unaffiliated third party containing customary provisions regarding the payment and refunding of such deposits).(b) Section 6.02 of the Credit Agreement is further amended by inserting “and Section 6.02(f)” at the end of the finalparagraph of such section.2.6 Amendment to Section 8.14(a). Section 8.14(a) of the Credit Agreement is hereby amended and restated in its entirety asfollows:(a) In connection with each redetermination of the Borrowing Base, the Borrower shall review the Reserve Reportand the list of current Mortgaged Properties (as described in Section 8.12(c)(iv)) to ascertain whether the Mortgaged Propertiesrepresent at least 90% of the total value of the Oil and Gas Properties evaluated in the most recently completed Reserve Reportafter giving effect to exploration and production activities, acquisitions, dispositions and production. In the event that theMortgaged Properties do not represent at least 90% of such total value, then the Borrower shall, and shall cause the Subsidiariesto, grant, within thirty (30) days of delivery of the certificate required under Section 8.12(c), to the Administrative Agent assecurity for the Indebtedness a first-priority Lien interest (provided that Excepted Liens of the type described in clauses (a) to(d) and (f) of the definition thereof may exist, but subject to the provisos at the end of such definition) on additional Oil and GasProperties of the Credit Parties not already subject to a Lien of the Security Instruments such that after giving effect thereto, theMortgaged Properties will represent at least 90% of such total value; provided that notwithstanding the foregoing, until the datethat is thirty (30) days following the Fifth Amendment Effective Date (or such later date as the Administrative Agent may agreein its sole discretion), the Mortgaged Properties shall only need to represent 80% of the total value of the Oil and Gas Propertiesevaluated in the most recently completed Reserve Report. All such Liens will be created and perfected by and in accordancewith the provisions of deeds of trust, security agreements and financing statements or other Security Instruments, all in form andsubstance reasonably4Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.satisfactory to the Administrative Agent and in sufficient executed (and acknowledged where necessary or appropriate)counterparts for recording purposes. In order to comply with the foregoing, if any Subsidiary places a Lien on its Oil and GasProperties and such Subsidiary is not a Guarantor, then it shall become a Guarantor and comply with Section 8.14(b).2.7 Amendment to Section 9.04(b). Section 9.04(b) of the Credit Agreement is hereby amended and restated in its entirety asfollows:(b) Repayment of Senior Notes; Amendment to Terms of Senior Notes. The Parent, OP LLC and the Borrower willnot, and will not permit any of their respective Subsidiaries to, prior to the date that is ninety-one (91) days after the MaturityDate: (i) call, make or offer to make any optional or voluntary Redemption of or otherwise optionally or voluntarily Redeem(whether in whole or in part) the Senior Notes; provided that (A) the Parent may prepay the Senior Notes in one or moretransactions in an aggregate amount not to exceed the net cash proceeds of any sale of Equity Interests (other than DisqualifiedCapital Stock) of the Parent to the extent that (x) such prepayment is consummated within 180 days of the consummation ofsuch sale of Equity Interest and (y) after giving pro forma effect to such prepayment, no Default, Event of Default orBorrowing Base Deficiency shall have occurred and be continuing, and (B) the Parent may Redeem the Senior Notes in onemore transactions to the extent that (x) the Specified Redemption Test is satisfied at the time of such Redemption, (y) theamount paid in respect of any Senior Note does not exceed 60% of the stated principal amount of such Senior Note and (z) theaggregate cash consideration paid by the Parent in respect of all Redemptions of Senior Notes pursuant to this Section 9.04(b)(i)(B) shall not exceed $175,000,000, or (ii) amend, modify, waive or otherwise change, consent or agree to any amendment,modification, waiver or other change to, any of the terms of the Senior Notes or the Senior Notes Indenture if (A) the effectthereof would be to shorten its maturity or average life or increase the amount of any payment of principal thereof or increasethe rate or shorten any period for payment of interest thereon or (B) such action requires the payment of a consent fee(howsoever described), provided that the foregoing shall not prohibit the execution of supplemental indentures associated withthe incurrence of additional Senior Notes to the extent permitted by Section 9.02(j) or the execution of supplemental indenturesto add guarantors if required by the terms of any Senior Notes Indenture provided such Person complies with Section 8.14(b)or (C) with respect to Senior Notes that are subordinated to the Indebtedness or any other Debt, designate any Debt (other thanobligations of the Borrower and the Subsidiaries pursuant to the Loan Documents) as “Specified Senior Indebtedness” or“Specified Guarantor Senior Indebtedness” or give any such other Debt any other similar designation for the purposes of anyIndenture related to Senior Notes that are subordinated to the Indebtedness or any other Debt.5Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.2.8 Replacement of Annex I. Annex I to the Credit Agreement is hereby amended and restated in its entirety with Annex Iattached hereto and Annex I attached hereto shall be deemed to be attached as Annex I to the Credit Agreement.2.9 Amendment to Exhibit B. Exhibit B to the Credit Agreement is hereby amended and restated in its entirety with Exhibit Battached hereto.Section 3. Borrowing Base Redetermination and Reduction in Aggregate Elected Commitment Amounts. Pursuant to Section 2.07 ofthe Credit Agreement, the Administrative Agent and the Lenders agree that for the period from and including the Fifth AmendmentEffective Date to but excluding the next Redetermination Date, the amount of the Borrowing Base shall be equal to $1,150,000,000.Notwithstanding the foregoing, the Borrowing Base may be subject to further adjustments from time to time pursuant to Section 2.7(e),Section 8.13(c) or Section 9.12(d). For the avoidance of doubt, the redetermination herein shall constitute the April 1, 2016 ScheduledRedetermination and the next Scheduled Redetermination shall be the October 1, 2016 Scheduled Redetermination. Furthermore, theparties hereto agree that the Aggregate Elected Commitment Amounts shall be reduced to $1,150,000,000.00, effective as of the FifthAmendment Effective Date, and the Borrower and the Lenders agree and acknowledge that the Elected Commitment of each Lendershall be as more particularly set forth on Annex I attached hereto.Section 4. Conditions Precedent. This Fifth Amendment shall become effective as of the date when each of the following conditionsis satisfied (or waived in accordance with Section 12.02 of the Credit Agreement) (the “Fifth Amendment Effective Date”):4.1 The Administrative Agent shall have received from the Borrower, each Guarantor and the Required Lenderscounterparts (in such number as may be requested by the Administrative Agent) of this Fifth Amendment signed on behalf of suchPerson.4.2 The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the date hereof,including those fees and other amounts payable pursuant to the Fee Letter dated as of February 23, 2016.4.3 No Default shall have occurred and be continuing as of the date hereof after giving effect to the terms of this FifthAmendment.4.4 The Administrative Agent shall have received such other documents as the Administrative Agent or its special counselmay reasonably require.The Administrative Agent is hereby authorized and directed to declare this Fifth Amendment to be effective when it hasreceived documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forthin this Section 4 or the waiver of such conditions as permitted hereby. Such declaration shall be final, conclusive and binding upon allparties to the Credit Agreement for all purposes.Section 5. Post-Closing Covenant. On or prior to the date that is thirty (30) days following the Fifth Amendment Effective Date (orsuch later date as the Administrative Agent may agree in6Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.its sole discretion), the Borrower and each Guarantor shall deliver to the Administrative Agent such title information and additionalduly executed mortgages and/or mortgage supplements as may be necessary to comply with the requirements of Section 8.14(a) of theCredit Agreement as modified by this Fifth Amendment.Section 6. Miscellaneous.6.1 Confirmation and Effect. The provisions of the Credit Agreement, as amended by this Fifth Amendment, shall remain infull force and effect following the effectiveness of this Fifth Amendment. Each reference in the Credit Agreement to “thisAgreement”, “hereunder”, “hereof”, “herein” or any other word or words of similar import shall mean and be a reference to theCredit Agreement as amended hereby, and each reference in any other Loan Document to the Credit Agreement or any word orwords of similar import shall be and mean a reference to the Credit Agreement as amended hereby.6.2 No Waiver. Neither the execution by the Administrative Agent or the Lenders of this Fifth Amendment, nor any otheract or omission by the Administrative Agent or the Lenders or their officers in connection herewith, shall be deemed a waiver by theAdministrative Agent or the Lenders of any Defaults or Events of Default which may exist, which may have occurred prior to thedate of the effectiveness of this Fifth Amendment or which may occur in the future under the Credit Agreement and/or the otherLoan Documents. Similarly, nothing contained in this Fifth Amendment shall directly or indirectly in any way whatsoever either: (a)impair, prejudice or otherwise adversely affect the Administrative Agent’s or the Lenders’ right at any time to exercise any right,privilege or remedy in connection with the Loan Documents with respect to any Default or Event of Default, (b) except as expresslyprovided herein, amend or alter any provision of the Credit Agreement, the other Loan Documents, or any other contract orinstrument, or (c) constitute any course of dealing or other basis for altering any obligation of the Borrower or any right, privilege orremedy of the Administrative Agent or the Lenders under the Credit Agreement, the other Loan Documents, or any other contract orinstrument.6.3 Ratification and Affirmation; Representations and Warranties. Each Credit Party hereby (a) acknowledges the terms ofthis Fifth Amendment; (b) ratifies and affirms its obligations under, and acknowledges its continued liability under, each LoanDocument to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect asexpressly amended hereby and (c) represents and warrants to the Lenders that as of the date hereof, after giving effect to the terms ofthis Fifth Amendment: (i) all of the representations and warranties contained in each Loan Document to which it is a party are trueand correct in all material respects (or, if already qualified by materiality, Material Adverse Effect or a similar qualification, true andcorrect in all respects), except to the extent any such representations and warranties are expressly limited to an earlier date, in whichcase, such representations and warranties shall continue to be true and correct in all material respects (or, if already qualified bymateriality, Material Adverse Effect or a similar qualification, true and correct in all respects) as of such specified earlier date, (ii) noDefault or Event of Default has occurred and is continuing and (iii) no event or events have occurred which individually or in theaggregate could reasonably be expected to have a Material Adverse Effect.7Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.6.4 Counterparts. This Fifth Amendment may be executed by one or more of the parties hereto in any number of separatecounterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of thisFifth Amendment by facsimile or email transmission shall be effective as delivery of a manually executed counterpart hereof.6.5 No Oral Agreement. This Fifth Amendment, the Credit Agreement and the other Loan Documents executed inconnection herewith and therewith represent the final agreement between the parties and may not be contradicted by evidence ofprior, contemporaneous, or unwritten oral agreements of the parties. There are no subsequent oral agreements between the parties.6.6 GOVERNING LAW. THIS FIFTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED INACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.6.7 Payment of Expenses. In accordance with Section 12.03 of the Credit Agreement, the Borrower agrees to pay orreimburse the Administrative Agent for all of its reasonable out-of-pocket costs and reasonable expenses incurred in connection withthis Fifth Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including,without limitation, the reasonable fees and disbursements of counsel to the Administrative Agent.6.8 Severability. Any provision of this Fifth Amendment which is prohibited or unenforceable in any jurisdiction shall, as tosuch jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisionshereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision inany other jurisdiction.6.9 Successors and Assigns. This Fifth Amendment shall be binding upon and inure to the benefit of the parties hereto andtheir respective successors and assigns.6.10 Loan Document. This Fifth Amendment shall constitute a “Loan Document” under and as defined in Section 1.02 ofthe Credit Agreement.[SIGNATURES BEGIN NEXT PAGE]8Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.IN WITNESS WHEREOF, the parties hereto have caused this Fifth Amendment to be duly executed as of the date first writtenabove.BORROWER: OASIS PETROLEUM NORTH AMERICA LLC By: /s/ Michael Lou Name:Michael Lou Title:Executive Vice President and Chief Financial OfficerGUARANTORS: OASIS PETROLEUM INC. OASIS PETROLEUM LLC OASIS PETROLEUM MARKETING LLC OASIS WELL SERVICES LLC OASIS MIDSTREAM SERVICES LLC By: /s/ Michael Lou Name:Michael Lou Title:Executive Vice President and Chief Financial Officer Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.ADMINISTRATIVE AGENT, ISSUING BANK AND LENDER:WELLS FARGO BANK, N.A., as Administrative Agent, Issuing Bank and as a Lender By: /s/ Edward Pak Name: Edward Pak Title: Director Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.LENDERS: CITIBANK, N.A., as a Lender By: /s/ Phil Ballard Name: Phil Ballard Title: Vice President Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. JPMORGAN CHASE BANK, N.A., as a Lender By: /s/ Anson Williams Name: Anson Williams Title: Authorized Signatory Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. ROYAL BANK OF CANADA, as a Lender By: /s/ Evans Swann Jr. Name: Evans Swann Jr. Title: Authorized Signatory Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. CAPITAL ONE, NATIONAL ASSOCIATION, as a Lender By: /s/ Kristin N. Oswald Name: Kristin N. Oswald Title: Vice President Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. COMPASS BANK, as a Lender By: /s/ Kathleen J. Bowen Name: Kathleen J. Bowen Title: Managing Director Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. CANADIAN IMPERIAL BANK OF COMMERCE, NEWYORK BRANCH, as a Lender By: /s/ Trudy Nelson Name: Trudy Nelson Title: Authorized Signatory By: /s/ William M. Reid Name: William M. Reid Title: Authorized Signatory Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. DEUTSCHE BANK AG NEW YORK BRANCH, as a Lender By: /s/ Peter Cucchiara Name: Peter Cucchiara Title: Vice President By: /s/ Michael Shannon Name: Michael Shannon Title: Vice President Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. ING CAPITAL LLC, as a Lender By: /s/ Josh Strong Name: Josh Strong Title: Director By: /s/ Michael Price Name: Michael Price Title: Managing DirectorSignature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. CITIZENS BANK, N.A., as a Lender By: /s/ Scott Donaldson Name: Scott Donaldson Title: Senior Vice President Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. U.S. BANK NATIONAL ASSOCIATION, as a Lender By: /s/ John C. Lozano Name: John C. Lozano Title: Vice President Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. ZB, N.A. DBA AMEGY BANK, as a Lender By: /s/ G. Scott Collins Name: G. Scott Collins Title: Senior Vice President By: /s/ John Moffitt Name: John Moffitt Title: Assistant Vice PresidentSignature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. BOKF, NATIONAL ASSOCIATION DBA BANK OF TEXAS, as a Lender By: /s/ Mari Salazar Name: Mari Salazar Title: SVP, Energy Lending Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. BRANCH BANKING TRUST COMPANY, as a Lender By: /s/ Kelly Graham Name: Kelly Graham Title: Vice President Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. COMERICA BANK, as a Lender By: /s/ William Robinson Name: William Robinson Title: Senior Vice President Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH, as a Lender By: /s/ Nupur Kumar Name: Nupur Kumar Title: Authorized Signatory By: /s/ Warren Van Heyst Name: Warren Van Heyst Title: Authorized SignatorySignature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. REGIONS BANK, as a Lender By: /s/ Iris Zhang Name: Iris Zhang Title: Director Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. IBERIABANK, as a Lender By: /s/ Stacy Goldstein Name: Stacy Goldstein Title: Senior Vice President Signature Page to Fifth Amendment to Second Amended and Restated Credit Agreement(Oasis Petroleum North America LLC)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.ANNEX ILIST OF MAXIMUM CREDIT AMOUNTSANDELECTED COMMITMENTSAggregate Maximum Credit Amounts and Aggregate Elected Commitment AmountsName of LenderApplicable PercentageMaximum Credit AmountElected CommitmentWells Fargo Bank, N.A.11.147540980%$278,688,524.52$128,196,721.29Citibank, N.A.9.836065574%$245,901,639.31$113,114,754.10JPMorgan Chase Bank, N.A.9.836065574%$245,901,639.31$113,114,754.10Royal Bank of Canada8.852459016%$221,311,475.41$101,803,278.69Capital One, National Association5.573770492%$139,344,262.31$64,098,360.66Compass Bank5.573770492%$139,344,262.31$64,098,360.66Canadian Imperial Bank Of Commerce, NewYork Branch5.573770492%$139,344,262.31$64,098,360.66Deutsche Bank AG New York Branch5.573770492%$139,344,262.31$64,098,360.66ING Capital LLC5.573770492%$139,344,262.31$64,098,360.66Citizens Bank, N.A.5.573770492%$139,344,262.31$64,098,360.66U.S. Bank National Association5.573770492%$139,344,262.31$64,098,360.66Amegy Bank National Association3.278688525%$81,967,213.12$37,704,918.03BOKF, National Association DBA Bank of Texas3.278688525%$81,967,213.12$37,704,918.03Branch Banking and Trust Company3.278688525%$81,967,213.12$37,704,918.03Comerica Bank3.278688525%$81,967,213.12$37,704,918.03Credit Suisse AG, Cayman Islands Branch3.278688525%$81,967,213.12$37,704,918.03Regions Bank3.278688525%$81,967,213.12$37,704,918.03Iberiabank1.639344262%$40,983,606.56$18,852,459.02 TOTAL100.00%$2,500,000,000.00$1,150,000,000.00EXHIBIT AAnnex ISource: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXHIBIT B FORM OF BORROWING REQUEST[ ], 201[ ]Oasis Petroleum North America LLC, a Delaware limited liability company (the “Borrower”), pursuant to Section 2.03 of theSecond Amended and Restated Credit Agreement dated as of April 5, 2013 (together with all amendments, restatements, supplementsor other modifications thereto, the “Credit Agreement”) among the Borrower, Oasis Petroleum Inc., a Delaware corporation (the“Parent”), Oasis Petroleum LLC, a Delaware limited liability company (“OP LLC”), Wells Fargo Bank, N.A., as AdministrativeAgent and the other agents and lenders (the “Lenders”) which are or become parties thereto (unless otherwise defined herein, eachcapitalized term used herein is defined in the Credit Agreement), hereby request a Borrowing as follows:(i) Aggregate amount of the requested Borrowing is $[ ];(ii) Date of such Borrowing is [ ], 201[ ];(iii) Requested Borrowing is to be [an ABR Borrowing] [a Eurodollar Borrowing];(iv) In the case of a Eurodollar Borrowing, the initial Interest Period applicable thereto is [ ];(v) Amount of Borrowing Base in effect on the date hereof is $[ ];(vi) Amount of the Aggregate Elected Commitment Amounts on the date hereof is $[ ];(vii) Total Revolving Credit Exposures on the date hereof (i.e., outstanding principal amount of Loans and total LC Exposure)is $[ ]; and(viii) Pro forma total Revolving Credit Exposures (giving effect to the requested Borrowing) is $[ ];(ix) At the time of and immediately after giving effect to the requested Borrowing, the Borrower together with the other CreditParties shall not have any cash or cash equivalents (other than cash collateral) in excess of $50,000,000 in the aggregate (other than (i)any cash set aside to pay royalty obligations of the Credit Parties then due and owing to unaffiliated third parties and for which theCredit Parties have issued checks or have initiated wires or ACH transfers (or will issue checks or initiate wires or ACH transferswithin 24 hours of such time) in order to pay, (ii) any cash set aside to pay in the ordinary course of business amounts (other thanroyalty obligations) of the Credit Parties then due and owing to unaffiliated third parties and for which the Credit Parties have issuedchecks or have initiated wires or ACH transfers in order to pay and (iii) any cash of the Credit Parties constituting purchase pricedeposits held in escrow by an unaffiliated third party pursuant to a binding and enforceable purchase and sale agreement with anunaffiliated third party containing customary provisions regarding the payment and refunding of such deposits); andExhibit BSource: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(x) Location and number of the Borrower’s account to which funds are to be disbursed, which shall comply with therequirements of Section 2.05 of the Credit Agreement, is as follows:[ ][ ][ ][ ][ ]Exhibit BSource: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The undersigned certifies that he/she is the [ ] of the Borrower, and that as such he/she is authorized to execute this certificateon behalf of the Borrower. The undersigned further certifies (only in his/her capacity as an officer and not individually), represents andwarrants on behalf of the Borrower that the Borrower is entitled to receive the requested Borrowing under the terms and conditions ofthe Credit Agreement.OASIS PETROLEUM NORTH AMERICA LLCBy: Name: Title: Exhibit BSource: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXHIBIT 12.1Oasis Petroleum Inc.Computation of Ratio of Earnings to Fixed Charges Year Ended December 31, 2011 2012 2013 2014 2015 Earnings Income (loss) before income taxes $126,179 $245,874 $363,017 $814,468 $(56,371)Add: Fixed charges 32,950 73,932 112,282 167,890 170,624Add: Amortization of capitalized interest 119 671 1,009 1,718 3,315Less: Capitalized interest (3,073) (3,298) (4,592) (8,850) (18,582)Total earnings $156,175 $317,179 $471,716 $975,226 $98,986 Fixed charges Interest expense $29,618 $70,143 $107,165 $158,390 $149,648Capitalized interest 3,073 3,298 4,592 8,850 18,582Rental expense attributable to interest 259 491 525 650 2,394Total fixed charges $32,950 $73,932 $112,282 $167,890 $170,624 Ratio of earnings to fixed charges(1)(2) 4.74 4.29 4.20 5.81 — (1)The Company had no preferred stock outstanding for any period presented, and accordingly, the ratio of earnings to combined fixed charges andpreferred stock dividends is the same as the ratio of earnings to fixed charges.(2)Due to the Company's net pre-tax loss for the year ended December 31, 2015, the ratio coverage was less than 1:1. The Company would have neededadditional earnings of $71.6 million for the year ended December 31, 2015 to achieve a coverage of 1:1.Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 21.1List of Subsidiaries of Oasis Petroleum Inc. Name of Subsidiary Jurisdiction of Incorporation or OrganizationOasis Midstream Services LLC Delaware Oasis Petroleum LLC Delaware Oasis Petroleum Marketing LLC Delaware Oasis Petroleum North America LLC Delaware Oasis Well Services LLC DelawareSource: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXHIBIT 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-197440) and Forms S-8 (No. 333-167664 and No.333-206025) of Oasis Petroleum Inc. of our report dated February 25, 2016 relating to the consolidated financial statements and the effectiveness of internalcontrol over financial reporting, which appears in this Form 10-K./s/ PricewaterhouseCoopers LLPHouston, TexasFebruary 25, 2016Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 23.2DEGOLYER AND MACNAUGHTON5001 SPRING VALLEY ROADSUITE 800 EASTDALLAS, TEXAS 75244February 25, 2016Oasis Petroleum Inc.1001 Fannin Street, Suite 1500Houston, Texas 77002Ladies and Gentlemen:We hereby consent to the reference to DeGolyer and MacNaughton and to the incorporation of the estimates contained in our“Report as of December 31, 2015 on Reserves and Revenue owned by Oasis Petroleum Inc.” (our Report) in Part 1 and in the “Notes toConsolidated Financial Statements” portions of the Annual Report on Form 10-K of Oasis Petroleum Inc. for the year ended December31, 2015 (the Annual Report). We further consent to the incorporation of estimates contained in our “Appraisal Report as of December31, 2014 on Certain Properties owned by Oasis Petroleum Inc.” and our “Appraisal Report as of December 31, 2013 on CertainProperties owned by Oasis Petroleum Inc.” In addition, we hereby consent to the incorporation by reference of our letter report datedJanuary 26, 2016 in the “Exhibits, Financial Statement Schedules” portion of the Annual Report. We further consent to theincorporation by reference of references to DeGolyer and MacNaughton and to our Report in Oasis Petroleum Inc.’s RegistrationStatements on Form S-3 (File No. 333-197440) and Forms S-8 (File No. 333-167664 and File No. 333-206025). Very truly yours, DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXHIBIT 31.1CERTIFICATION OF CHIEF EXECUTIVE OFFICERPURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDEDI, Thomas B. Nusz, certify that:1.I have reviewed this annual report on Form 10-K of Oasis Petroleum Inc. (the “registrant”);2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others withinthose entities, particularly during the period in which this report is being prepared;b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles;c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto materially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; andb.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 25, 2016/s/ Thomas B. Nusz Thomas B. Nusz Chairman and Chief Executive Officer (Principal Executive Officer)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXHIBIT 31.2CERTIFICATION OF CHIEF EXECUTIVE OFFICERPURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDEDI, Michael H. Lou, certify that:1.I have reviewed this annual report on Form 10-K of Oasis Petroleum Inc. (the “registrant”);2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others withinthose entities, particularly during the period in which this report is being prepared;b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles;c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto materially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; andb.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 25, 2016/s/ Michael H. Lou Michael H. Lou Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXHIBIT 32.1CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In connection with the annual report of Oasis Petroleum Inc. (the “Company”) on Form 10-K for the year ended December 31, 2015 as filed with theSecurities and Exchange Commission on the date hereof (the “Report”), I, Thomas B. Nusz, Chairman and Chief Executive Officer of the Company, certify,pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of theCompany. Date: February 25, 2016/s/ Thomas B. Nusz Thomas B. Nusz Chairman and Chief Executive Officer (Principal Executive Officer)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXHIBIT 32.2CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In connection with the annual report of Oasis Petroleum Inc. (the “Company”) on Form 10-K for the year ended December 31, 2015 as filed with theSecurities and Exchange Commission on the date hereof (the “Report”), I, Michael H. Lou, Executive Vice President and Chief Financial Officer of theCompany, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of theCompany.Date: February 25, 2016/s/ Michael H. Lou Michael H. Lou Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Source: Oasis Petroleum Inc., 10-K, February 25, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.

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