Midstates Petroleum Co. Annual Report 2013

Plain-text annual report

2013 ANNUAL REPORT RENEWED FOCUS MIDSTATES PETROLEUM COMPANY, INC. is an independent exploration and production company focused on the application of modern drilling and completion techniques in oil and liquids-rich basins in the onshore U.S. Midstates’ drilling and completion efforts are currently focused in the Mississippian Lime oil play in Oklahoma and the Anadarko Basin in Texas and Oklahoma. The Company’s operations also include the upper Gulf Coast tertiary trend in central Louisiana. During 2013, Midstates grew its proved reserves 69% to 127.8 million barrels of oil equivalent, of which 43% was oil and 20% was NGLs. Approximately 38% of year-end 2013 reserves was proved developed. The Company increased its annual production 139% in 2013 to 23,927 Boe per day, of which 45% was oil and 20% was NGLs. Successful organic drilling in 2013 replaced 500% of production with new reserves. FOCUS AREAS: MISSISSIPPIAN LIME • Expansive liquids-rich carbonate hydrocarbon system • Properties being developed solely with horizontal wells using multi- stage fracturing technology • At year-end 2013, the area represented 53% of total proved reserves ANADARKO BASIN • Thick geologic sections of multi-stacked pay with a focus on the Cleveland, Marmaton, Cottage Grove and Tonkowa formations • Properties are being developed with horizontal wells and multi- stage fracturing technology • At year-end 2013, the area represented 29% of total proved reserves Proved Reserves (MMBoe) 127.8 37% 20% 43% 75.5 31% 19% 50% 25% 15% 26.2 60% 150 120 90 60 30 0 2011 2012 2013 Daily Production (Boe/Day) 23,927 25000 35% 20000 20% 45% 9,999 26% 17% 57% 7,499 30% 59% 11% 2011 2012 2013 Oil NGLs Gas Annual Adjusted EBITDA(c) (In Millions) Proved Reserves (MMBoe) $330 127.8 37% 20% 43% 75.5 $145 31% 19% 50% 2012 2012 2013 2013 $153 26.2 60% 2011 2011 25% 15% 15000 10000 5000 0 350 150 300 120 250 90 200 150 60 100 30 50 0 0 Oil NGLs Gas Daily Production (Boe/Day) 23,927 25000 35% 20000 20% 45% 9,999 26% 17% 57% 7,499 30% 59% 11% 2011 2012 2013 Annual Adjusted EBITDA(c) (In Millions) $330 $153 $145 2011 2012 2013 15000 10000 5000 0 350 300 250 200 150 100 50 0 100 80 60 40 20 0 100 80 60 40 20 0 100 80 60 40 20 0 100 80 60 40 20 0 100 80 60 40 20 0 100 80 60 40 20 0 100 80 60 40 20 0 100 80 60 40 20 0 100 80 60 40 20 0 100 80 60 40 20 0 100 80 60 40 20 0 100 80 60 40 20 0 Our Areas of Operation MID - CONTINENT REGION: Operations in the Mid-Continent region are focused in the Mississippian Lime play in Woods and Alfalfa Counties in Oklahoma and in the Anadarko Basin properties in Northwest Oklahoma and Texas MAP KEY FOCUS AREAS GULF COA S T REGION: Operations in the Gulf Coast region are focused in the Upper Gulf Coast Tertiary trend in several parishes in central Louisiana To my fellow stakeholders: Let me begin by thanking John Crum, our former Chairman, President and CEO, for guiding us through our IPO and building a solid foundation that will allow us to continue to grow into the future. I also want to acknowledge and thank the talented team we have assembled at Midstates; they are the catalyst to unlocking the funda- mental value that resides within our assets. These past two years as a public company have been highlighted by a series of both accomplishments and challenges. We began as a single basin company focused on the Wilcox trend in central Louisiana, but within our short life, we completed two large acquisitions to broaden our growth opportunities by gaining entry into the Mississippian Lime in 2012 and the Anadarko Basin in 2013. We have consistently achieved record growth since our IPO, having increased production 219%, expanded reserves 388% and grown our Adjusted EBITDA to an annualized run-rate in excess of $475 million at year-end 2013. Last year, successful organic drilling activities replaced 500% of 2013 production at a competitive cost of $13.59 per Boe, while strategic acquisitions added 37 million barrels of oil equivalent reserves, primarily in the Anadarko Basin, at an attractive cost of $16.48 per Boe. While we are extremely proud of these accomplishments, our rapid growth stressed our balance sheet and created liquidity concerns. Our challenge is to address the balance sheet and liquidity while ensuring our rapid growth translates into strong shareholder value creation. Our Board of Directors and employees are focused on delivering the value driven growth opportunities that we know reside within our asset base. We believe that we can most effectively achieve value growth by delivering financial stability and demonstrating capital efficiency. This means concentrating on our core areas in the Mississippian Lime and Anadarko Basin, optimizing our drilling and operating costs, and expanding and high-grading our well location inventory. These actions will allow us to improve net asset value and grow cash flow, and increase production, reserves and resource potential in a prudent manner. On the financial front, we recently executed an agreement to sell the Pine Prairie portion of our Gulf Coast assets for $170 million and have amended our revolving credit facility to provide a borrowing base of $475 million supported exclusively by our Mid-Continent assets. These are significant first steps in our broader plan to improve our financial flexibility and redirect our capital into the highest return proj- ects. With the expected proceeds from the Pine Prairie sale, borrowing capacity under our revised revolver and our growing cash flow, we are confident that we now have sufficient funds for our needs through at least the end of 2015, without raising additional capital or equity. To further strengthen our balance sheet and increase our future financial flexibility, we will continue to look at additional property sales, joint ventures, drilling farm-outs and other options. Proved Reserves (MMBoe) 127.8 37% 20% 43% 75.5 31% 19% 50% 25% 15% 26.2 60% 2011 2012 2013 150 120 90 60 30 0 Daily Production (Boe/Day) 23,927 25000 35% 20000 20% 45% 9,999 26% 17% 57% 7,499 30% 59% 11% 2011 2012 2013 Annual Adjusted EBITDA (In Millions) $330 $153 $145 2011 2012 2013 100 80 60 40 20 0 100 80 60 40 100 80 60 40 20 0 100 80 60 40 20 0 100 80 100 60 40 80 60 40 20 20 We are growing the Company with our leading Mississippian Lime position, where production is up 100% and reserves are up 76% year-over-year. The wells we have drilled confirm that we have amassed some of the best acreage in the Mississippian Lime trend due to their strong initial production rates and solid ultimate recoveries. It is important that we continue to deliver these high rate of return wells to demon- strate capital efficiency and grow cash flow. The prolific, multi-horizon Anadarko Basin acreage we acquired last year is showing very promising results in the Cleveland formation. We are also excited by some of our recent well results in our other current target formations, the Tonkawa, Cottage Grove, and Marmaton. We look forward to leveraging our knowledge gained in the Mississippian Lime to this exciting new area of operation. 0 20 0 0 We believe that we can most effectively achieve value growth by delivering financial stability and demonstrating capital efficiency. 15000 10000 5000 0 350 300 250 200 150 100 50 0 Looking ahead into the remainder of 2014, we will strive to demonstrate operational excellence and allocate capital judiciously between our two core areas to optimize value. We believe that these assets provide us the platform from which we can again not only achieve record growth in production and Adjusted EBITDA, but, more impor- tantly, also grow shareholder value. In closing, I am pleased to serve as the Interim President and CEO of Midstates as your Board moves forward with the selection of a new leader for our Company. I want to once again thank all of our employees for their tremendous efforts this past year. It has been an eventful, challenging and yet exciting year for all of us. Most importantly, I thank you, our shareholders, for your continued support and patience while we strive to unlock the value we know exists within the Company. With your continued sup- port, the guidance from our Board, and the execution of our team, we are confident we can accomplish these goals. Dr. Peter J. Hill Interim President and Chief Executive Officer Financial Highlights ($ amounts in thousands, except share and per share amounts) 2013 2012 2011 2010 Years Ended December 31, FINANCIAL DATA Total revenues Operating income (loss) Net income (loss) Net income (loss) attributable to common shareholders Net income (loss) per share Weighted average shares outstanding Net cash provided by operating activities Adjusted EBITDA(c) Total assets Long-term debt Stockholders’/members’ equity $ 469,506 (407,409) (343,985) (359,574) (5.47) 65,766 227,102 330,144 2,342,107 1,701,150 339,999 $ 247,673 20,543 (150,097) (156,597) (2.61) 59,979 137,249 144,619 1,684,010 694,000 677,469 $ 209,433 18,728 16,657 16,657 (a) (a) 141,550 152,616 624,656 234,800 285,502 $ 63,052 (15,644) (15,635) (15,635) (a) (a) 50,768 53,274 427,004 89,600 255,879 OPERATING DATA Net production (per day) Oil (Bbls) Natural gas liquids (Bbls) Gas (Mcf) Total (Boe) Total estimated net proved reserves: Oil (MBbls) Natural gas liquids (MBbls) Gas (MMcf) Total (MBoe) Percentage Proved Developed SEC PV-10 Value (before taxes) Total Gross Active Wells Total Net Acres 10,697 4,711 51,116 23,927 54,899 26,156 280,198 127,755 5,719 1,686 15,559 9,999 37,527 14,198 142,403 75,459 4,410 843 13,475 7,499 15,716 4,031 38,692 26,196 2,589 203 6,171 3,820 11,927 314 27,906 16,892 38% 37% 43% 47% $ 2,067,834 722 308,208 $ 1,489,087 294 249,739 $ 692,745 92 108,741 $298,088 (b) (b) (a) Midstates was not a public company until 2012. (b) Information is not available. (c) For a reconciliation of Adjusted EBITDA to the nearest GAAP financial measure, please see the Company’s Form 10-K filed with the Securities and Exchange Commission on March 24, 2014. Use these links to rapidly review the documentMIDSTATES PETROLEUM COMPANY, INC. TABLE OF CONTENTS MIDSTATES PETROLEUM COMPANY, INC. INDEX TO CONSOLIDATED FINANCIAL STATEMENTSTable of Contents UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549Form 10-KCommission File Number: 001-35512MIDSTATES PETROLEUM COMPANY, INC.(Exact name of registrant as specified in its charter)Delaware(State or other jurisdiction ofincorporation or organization) 45-3691816(I.R.S. EmployerIdentification No.)4400 Post Oak Parkway, Suite 1900; Houston,Texas(Address of principal executive offices) 77027(Zip Code)Registrant's telephone number, including area code: (713) 595-9400 Securities registered pursuant to Section 12(b) of the Act: Securities registered pursuant to Section 12(g) of the Act: None ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934For the fiscal year ended December 31, 2013ORo TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT OF 1934For the transition period from to .Common stock, $0.01 par value New York Stock Exchange(Title of each class) (Name of each exchange on whichregistered) Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o 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 o No  Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act 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 suchfiling requirements for the past 90 days. Yes  No o 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 suchshorter period that the registrant was required to submit and post such files). Yes  No o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained,to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III or any amendment to theForm 10-K  Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reportingcompany. See definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. Check one: Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No  The aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant was approximately $180 million based uponthe closing price of such stock on June 28, 2013, the last business day of the registrant's most recently completed second fiscal quarter, of $5.41 pershare. The number of shares outstanding of our stock at March 18, 2014 is shown below: Large accelerated filer o Accelerated filer  Non-accelerated filer o(Do not check if asmaller reporting company) Smaller reporting company oClass Number of shares outstandingCommon stock, $0.01 par value 70,420,804Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.TABLE OF CONTENTS 2Item Page PART I 1. BUSINESS 7 1A. RISK FACTORS 32 1B. UNRESOLVED STAFF COMMENTS 53 2. PROPERTIES 53 3. LEGAL PROCEEDINGS 53 4. MINE SAFETY DISCLOSURES 53 PART II 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERMATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 54 6. SELECTED FINANCIAL DATA 55 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDRESULTS OF OPERATIONS 58 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 80 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 82 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL DISCLOSURE 82 9A. CONTROLS AND PROCEDURES 82 9B. OTHER INFORMATION 86 PART III 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 86 11. EXECUTIVE COMPENSATION 86 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ANDRELATED STOCKHOLDER MATTERS 86 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTORINDEPENDENCE 86 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 86 PART IV 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 86 Table of ContentsCAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which arebeyond our control. All statements other than statements of historical fact included in this annual report are forward-looking statements, including,without limitation, statements regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects,plans and objectives of management. When used in this annual report, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "may,""continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements may include statements about our:•business strategy; •estimated future net reserves and present value thereof; •technology; •cash flows and liquidity; •financial strategy, budget, projections and operating results; •oil and natural gas realized prices; •timing and amount of future production of oil and natural gas; •availability of drilling and production equipment; •availability of oilfield labor; •availability of third party natural gas gathering and processing capacity; •the amount, nature and timing of capital expenditures, including future development costs; •availability and terms of capital; •drilling of wells, including our identified drilling locations; •successful results from our identified drilling locations; •marketing of oil and natural gas; •the integration and benefits of asset and property acquisitions or the effects of asset and property acquisitions or dispositions on our cashposition and levels of indebtedness; •infrastructure for salt water disposal and electricity; •sources of electricity utilized in operations and the related infrastructures; •costs of developing our properties and conducting other operations; •general economic conditions; •effectiveness of our risk management activities; •environmental liabilities; •counterparty credit risk; •the outcome of pending and future litigation; •governmental regulation and taxation of the oil and natural gas industry; •developments in oil-producing and natural gas-producing countries;3Table of Contents•uncertainty regarding our future operating results; and •plans, objectives, expectations and intentions contained in this annual report that are not historical. All forward-looking statements speak only as of the date of this annual report. You should not place undue reliance on these forward-lookingstatements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Although we believe that our plans,intentions and expectations reflected in or suggested by the forward-looking statements we make in this annual report are reasonable, we can give noassurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from thoseanticipated or implied in the forward-looking statements. We disclose important factors that could cause our actual results to differ materially from ourexpectations under "Risk Factors" and elsewhere in this annual report. These factors include:•variations in the market demand for, and prices of, oil, natural gas liquids and natural gas; •uncertainties about our estimated quantities of oil and natural gas reserves; •the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under ourrevolving credit facility; •access to capital and general economic and business conditions; •uncertainties about our ability to replace reserves and economically develop our current reserves; •risks in connection with acquisitions, including the Eagle Property and Anadarko Basin Acquisitions; •risks related to the concentration of our operations onshore in Oklahoma, Texas and Louisiana; •drilling results; •the potential adoption of new governmental regulations; and •our ability to satisfy future cash obligations and environmental costs. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for ourmanagement to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors,may cause actual results to differ materially from those contained in any forward-looking statements we may make. Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. Theaccuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by ourreserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. Ifsignificant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differfrom the quantities of oil and natural gas that are ultimately recovered.4Table of ContentsGLOSSARY OF OIL AND NATURAL GAS TERMS Bbl: One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or natural gas liquids. Boe: Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil. Boe/d: Barrels of oil equivalent per day. Completion: The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, orin the case of a dry hole, the reporting of abandonment to the appropriate agency. Dry hole: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such productiondo not exceed production expenses and taxes. Exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil inanother reservoir. MMBoe: One million barrels of oil equivalent. MMBtu: One million British thermal units. 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. NYMEX: The New York Mercantile Exchange. 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, operatingmethods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewalis reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbonsmust have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoirconsidered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoirthat can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of availablegeoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons,as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonablecertainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap,proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliabletechnology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improvedrecovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot projectin an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or ananalogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project orprogram was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the averageprice during the 12-month period prior to the ending date of the5Table of Contentsperiod covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period,unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 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 projects 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 individual and separate from other reservoirs. Spud or Spudding: The commencement of drilling operations of a new well. 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 a cash, penalty, or carried basis.6Table of ContentsPART I ITEM 1. BUSINESS This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations,estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties, and assumptions and areinfluenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See"Cautionary Note Regarding Forward Looking Statements" and "Risk Factors" located in this Form 10-K. In this section, references to "the Company," "we," "us," "our," and "Midstates" when used in the present tense, prospectively or for historicalperiods since April 25, 2012, refer to Midstates Petroleum Company, Inc. and its subsidiary, and for historical periods prior to April 25, 2012, refer toMidstates Petroleum Holdings LLC and its subsidiary, unless the context indicates otherwise.General Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holdingcompany for Midstates Petroleum Company LLC ("Midstates Sub"), which was previously a wholly-owned subsidiary of Midstates PetroleumHoldings LLC. Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Midstates PetroleumCompany, Inc.'s initial public offering on April 25, 2012, all of the interests in Midstates Petroleum Holdings LLC were exchanged for newly issuedcommon shares of Midstates Petroleum Company, Inc., and as a result, Midstates Sub became a wholly-owned subsidiary of Midstates PetroleumCompany, Inc. and Midstates Petroleum Holdings LLC ceased to exist as a separate entity. Our common stock, par value $0.01 per share, has beenlisted on the New York Stock Exchange (NYSE) since April 2012. On October 1, 2012, the Company closed on the acquisition of all of Eagle Energy Production, LLC's ("Eagle Energy") producing properties andundeveloped acreage located primarily in the Mississippian Lime liquids play in Oklahoma for $325 million in cash, before customary post-closingadjustments, and 325,000 shares of the Company's Series A Mandatorily Convertible Preferred Stock (the "Series A Preferred Stock") with an initialliquidation preference value of $1,000 per share (the "Eagle Property Acquisition"). The Company funded the cash portion of the Eagle PropertyAcquisition purchase price with a portion of the net proceeds from the private placement of $600 million in aggregate principal amount of 10.75%senior unsecured notes due 2020 (the "2020 Senior Notes"), which also closed on October 1, 2012. On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas andOklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (the "Anadarko Basin Acquisition"), beforecustomary post-closing adjustments. The Company funded the purchase price with a portion of the net proceeds from the private placement of$700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021 (the "2021 Senior Notes" and, together with the 2020 SeniorNotes, the "Senior Notes"), which also closed on May 31, 2013. Subsequent to the closing of the Eagle Property Acquisition and the Anadarko Basin Acquisition, the Company has oil and gas operations andproperties in Louisiana, Oklahoma and Texas. At December 31, 2013, the Company operated oil and natural gas properties and evaluated performanceas one reportable segment as there were not significantly different economic or operational environments within its oil and natural gas properties. On March 5, 2014, we executed a Purchase and Sale Agreement ("PSA") to sell all of our ownership interest in developed and undevelopedacreage in the Pine Prairie field area of Evangeline7Table of ContentsParish, Louisiana to a private buyer for a purchase price of $170 million in cash, subject to standard post-closing adjustments. The PSA has an effectivedate of November 1, 2013 and is expected to close on May 1, 2014. Acreage subject to the transaction totaled 3,907 gross (3,757 net) acres, and doesnot include our acreage and production in the western part of Louisiana in Beauregard Parish or other undeveloped acreage held outside the Pine Prairiefield. The proceeds from the sale will be used to pay down our revolving credit facility. The following table summarizes, by areas of operation, our estimated proved reserves as of December 31, 2013, their corresponding pre-tax PV-10 values and our fourth quarter 2013 average daily production rates (including those figures attributable to the Pine Prairie field that are subject to thePSA discussed above): During 2013, we incurred $1.2 billion in exploration, development and property acquisition expenditures, including $624.7 million for theAnadarko Basin Acquisition and $64.9 million for facilities and lease and seismic acquisition. Of the 124 wells spud in 2013, 121 gross (98 net) wells8 AverageDailyProductionfor ThreeMonthsEndedDecember 31,2013 Proved Reserves(1) PV-10(3) Oil(MBbl) NGL(MBbl) Gas(MMcf) Total(2)(MBoe) Areas of Operation %Oil(4) (inthousands) (Boe/day) Mississippian 24,239 14,221 176,264 67,836 56%$965,761 17,579 Anadarko Basin 15,816 8,555 75,612 36,973 66% 611,315 8,454 Gulf Coast 14,845 3,380 28,322 22,945 79% 490,758 5,154 Total 54,900 26,156 280,198 127,754 63%$2,067,834 31,187 Discounted Future Income Taxes (277,388) Standardized Measure of Discounted Future NetCash Flows(3) $1,790,446 (1)Oil, natural gas liquids and natural gas reserve quantities and related discounted future net cash flows have been derived from oil,natural gas liquids and natural gas prices calculated using an average of the first-day-of-the month price for each month within the12 months ended December 31, 2013, pursuant to current SEC and FASB guidelines. (2)Barrel of oil equivalents are determined using a ratio of one Bbl of crude to six Mcf of natural gas, which represents theirapproximate relative energy content. (3)Pre-tax PV-10 may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardizedmeasure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Pre-tax PV-10 iscomputed on the same basis as the standardized measure of discounted future net cash flows but without deducting future incometaxes. We believe pre-tax PV-10 is a useful measure for investors for evaluating the relative monetary significance of our oil andnatural gas properties. We further believe investors may utilize our pre-tax PV-10 as a basis for comparison of the relative sizeand value of our proved reserves to other companies because many factors that are unique to each individual company impact theamount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investmentrelated to our oil and natural gas properties and acquisitions. However, pre-tax PV-10 is not a substitute for the standardizedmeasure of discounted future net cash flows. Our pre-tax PV-10 does not purport to present the fair value of our proved oil andnatural gas reserves. (4)Includes volumes attributable to oil and NGLs.Table of Contentsresulted in productive completions and three gross (and net) wells were unsuccessful, yielding a 98% success rate. We expect to invest between $500 million and $550 million of capital for exploration, development and lease and seismic acquisition in 2014.Additionally, we expect to capitalize between $16 million and $22 million of interest expense.Growth Strategy Our goal is to grow our reserves, production and cash flows at an attractive rate of return on invested capital. We seek to achieve this goal throughthe following strategies: Development of our multi-year drilling inventory. We intend to drill and develop our current acreage position to maximize the value of ourprimarily oil and liquids rich resource potential.•Mississippian. Our Mississippian assets acquired on October 1, 2012 are located in Oklahoma and target the Mississippian Lime andHunton formations. The Mississippian Lime is an expansive carbonate hydrocarbon system located in the Anadarko Basin, primarily innorthern Oklahoma. We currently intend to continue development of these liquids rich properties using horizontal wells and multi-stagefrac technology. The Hunton formation is a limestone formation that produces primarily natural gas from our acreage in Lincoln County,Oklahoma. Because the Hunton targets primarily natural gas, our capital deployment will be focused on the Mississippian Lime untilnatural gas prices demonstrate sustained improvement from recent levels. At December 31, 2013, we had approximately 137,500 gross(97,200 net) acres under lease in the area, comprised of approximately 120,000 gross (84,300 net) leased acres in the MississippianLime and approximately 17,500 gross (12,900 net) acres in the Hunton. As of December 31, 2013, we had five drilling rigs in operation,and we currently have five drilling rigs in operation. We expect to spud between 95 to 105 gross (70 to 80 net) horizontal wells,including non-operated wells, during 2014 on this acreage. •Anadarko Basin. Our Anadarko Basin assets acquired on May 31, 2013 are located in Western Oklahoma and Texas and target multipleobjectives in the Pennsylvanian section. Specifically we are currently targeting the Cleveland, Marmaton, Cottage Grove and Tonkawaformations by utilizing horizontal wells and multi-stage frac technology. At December 31, 2013, we had approximately 161,500 gross(129,800 net) acres under lease in the Anadarko Basin, comprised of approximately 42,700 gross (34,300 net) leased acres in Oklahomaand approximately 118,800 gross (95,500 net) acres in the Texas. As of December 31, 2013, we had five drilling rigs in operation in thisarea, and we currently have five drilling rigs in operation. We expect to spud between 70 to 75 gross (47 to 50 net) horizontal wells,including non-operated wells, during 2014 on this acreage. •Gulf Coast. Our Gulf Coast assets are located in Louisiana and are characterized by thick geologic sections of tight sands within theTertiary Wilcox featuring multiple productive zones located within large geologic structural traps that are identifiable with 2D and 3Dseismic data. Our primary operating areas have well-established production histories. At December 31, 2013 we had approximately83,400 gross (81,200 net) acres under lease and/or lease option, comprised of 58,500 gross (56,500 net) acres under lease and 24,900gross (24,700 net) acres under lease options, targeting large, well-defined geologic structures that we believe will increase our reserves,production and cash flow. With the addition of the Anadarko assets and increased activity in the Mississippian, we have shifted capital tothose assets and dropped rigs in Louisiana. Our intent is to continue high grading inventory in Louisiana for future capital deployment.As of December 31, 2013, we had no drilling rigs in operation. We currently do not have any rigs in operation in the Gulf Coast areaand expect a reduction in activity versus prior year due to our current focus on exploitation of our Mississippian assets and our recently9Table of Contentsacquired Anadarko Basin Assets. As discussed above, on March 5, 2014, we executed a PSA to sell all of our ownership interest indeveloped and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer. Acreage subject tothe transaction totaled 3,907 gross (3,757 net) acres and is expected to close on May 1, 2014. Disciplined financial management. We intend to maintain a disciplined approach to our financial management in order to preserve our financialstability. We believe that this approach includes targeting a conservative leverage profile and maintaining the liquidity to develop our asset base acrossindustry cycles, as well as evaluating capital allocation decisions in the context of these goals. We have historically funded our activity through acombination of equity and debt securities, bank debt, and cash generated by operations. For example, we funded the Eagle Property Acquisition with acombination of cash proceeds from our $600 million 2020 Senior Notes offering and through the issuance of our Series A Preferred Stock. We fundedthe Anadarko Basin Acquisition with cash proceeds from our $700 million 2021 Senior Notes offering. In September 2013, our reserve-basedborrowing base under our revolving credit facility was increased from $425 million to $500 million. To reduce variability in cash flow from ourproperties and to enhance our reserve based borrowing facility, we periodically enter into commodity derivative contracts and target hedging themaximum volumes permitted under our revolving credit facility, which currently equates to approximately 80% of our total current oil volumes fromproved developed producing reserves. We believe the resulting increase in the predictability of our cash flow allows us to better schedule ourdevelopment activities and maximize the productivity of those efforts. We may also consider the sale of selected assets or oil and gas interests to theextent those actions would help us achieve our targeted financial profile. Maintain operatorship across a diverse asset base. Our diverse set of assets and high degree of operating control, facilitated by our position asoperator on the majority of our properties, provide flexibility with respect to drilling and completion techniques and the timing and amount of capitalexpenditures that support growth and help us meet our targeted financial profile. Utilize our technical and operating expertise to enhance returns. Our technical teams are focused on the application of modern reservoirevaluation and drilling and completion techniques to reduce risk and enhance returns in our core areas. We utilize 2D, 3D and micro seismic data,existing sub-surface well control data, detailed reservoir characterization and geologic and geochemical modeling to identify areas with significantexploration and development potential. These areas become targets for our leasing activity. Once we have identified a potential target, we attempt tomaximize returns by applying modern drilling and completion techniques that maximize recoveries in a cost efficient and economically attractive manner.We utilize reservoir evaluation methods such as conventional and rotary sidewall coring, pressure sampling and other reservoir description techniques tobetter understand the ultimate potential of a particular area. We believe future development across our acreage position can be further optimized withspecialized completion techniques, infill drilling, horizontal wellbore optimization and enhanced recovery methods. Selectively increase our acreage position. While we believe our existing acreage positions provide significant growth opportunities in theMississippian Lime, Anadarko Basin and the Upper Gulf Coast Tertiary trend, we continue to strategically increase our leasehold position in what webelieve are the most prospective areas of our acreage. We believe our current Oklahoma and Texas acreage is highly prospective in the Pennsylvanianand Mississippian Lime sections and may be prospective in both shallower and deeper geologic sections. We plan to continue targeting additionalonshore basins in North America that would allow us to extend our competencies to large undeveloped acreage positions in hydrocarbon trends similarto our existing core areas. Apply rigorous investment analysis to capital allocation decisions. We employ rigorous investment analysis to determine the allocation of capitalacross our many drilling opportunities and in evaluating potential acquisitions. We are focused on maximizing the internal rate of return on ourinvestment10Table of Contentscapital and screen drilling opportunities and acquisition opportunities by measuring risk and financial return, among other factors. We continuallyevaluate our inventory of potential investments by these measures, incorporating past drilling results, historical knowledge and new information wehave gathered.Our Competitive Strengths We have a number of competitive strengths that we believe will help us to successfully execute our business strategies: Oil and liquids weighted reserves, production and drilling locations with attractive economics. Our reserves, production and drilling locationsare primarily oil with associated liquids rich natural gas. For the year ended December 31, 2013, our production was comprised of approximately 45%oil and 20% NGLs and our year-end reserves consisted of 43% oil, 20% NGL and 37% natural gas. In the Gulf Coast, we also benefit from selling ouroil production to the Louisiana Light Sweet ("LLS") market, which has historically commanded a premium to West Texas Intermediate ("NYMEXWTI") oil prices due to its proximity to U.S. Gulf Coast refiners and the higher quality of the oil production sold in the LLS market. This premium hasaveraged approximately $14.88 per Bbl for the three years ended December 31, 2013. For the year ended December 31, 2013, the average realized pricebefore the effect of commodity derivative contracts for our oil production was $99.18 per Bbl, compared to an average NYMEX WTI price of $98.05per Bbl for the same period. Extensive technical knowledge, history and early mover advantage in our areas of operations. In our Mississippian Lime area, we and ourpredecessor in the field have demonstrated an early mover advantage in acquiring and developing acreage in the trend, spudding 151 horizontal wellsbetween 2010 and December 31, 2013. We believe our Mississippian team's early experience operating in this trend gives us a competitive advantagewith respect to completion techniques and infrastructure development. In the Anadarko Basin area, we also feel that we have an advantage due to thehistory of drilling horizontally in several of the Pennsylvanian sands since 2005. We successfully hired many of the operation and technical personnelfrom Panther Energy, which will allow us to continue to build on their success in this area. We have had operations in the Upper Gulf Coast Tertiarytrend since 1993. We believe our extensive operating experience in the trend provides us with an expansive technical understanding of the geologyunderlying our acreage and of the application of completion technologies and infrastructure design and optimization to our properties. We believe ourrelatively long history in the Gulf Coast area and experience interpreting well control data, core data and 2D and 3D seismic data provides us with aninformation advantage over our competitors in this trend and has allowed us to identify and acquire quality acreage at a relatively low cost. We believewe have developed amicable and mutually beneficial relationships with acreage owners in all of our core operating areas, which we believe alsoprovides us with a competitive advantage with respect to our leasing and development activity. We also benefit from long-term relationships with localservice companies and infrastructure providers that we believe contribute to our efficient low-cost operations. Experienced and aligned management team with extensive operating expertise. Our management team has extensive operating expertise in the oiland gas industry and significant public company executive experience at major and large independent oil and gas companies and oilfield servicescompanies, including Apache Corporation, Burlington Resources, ConocoPhillips and Anadarko Petroleum Corporation. Our management team has anaverage of 30 years of industry experience, including prior experience in various trends across the US and internationally. We believe our managementteam is one of our principal competitive strengths relative to our industry peers due to our team's proven track record of efficiently operating explorationand development programs. Additionally, our management team has a significant ownership interest in us, which we believe11Table of Contentsprovides incentive for them to prudently grow the value of our business for the benefit of all our stakeholders.Summary of Oil and Gas Properties and OperationsMississippian Lime Our Mississippian assets were acquired on October 1, 2012 and at December 31, 2013, consisted of approximately 84,300 net prospective acres inthe Mississippian Lime trend, with 79,800 net acres in Woods and Alfalfa Counties of Oklahoma, which we currently believe is the core of the trend.We currently intend to develop these liquids-rich properties using horizontal wells. We also own approximately 12,900 net acres in Lincoln County,Oklahoma, which produces from, and is prospective in, the Hunton formation. Our properties in this area represented 53% of our total proved reserves as of December 31, 2013. As of December 31, 2013, we held an averageworking interest and average net revenue interest of 71% and 55%, respectively, on our acreage in this area. For the three months ended December 31, 2013 and 2012 and the year ended December 31, 2013, our average daily production from this area wasas follows: In this area, our main operating area is defined by de-risked acreage primarily in Woods County, where we are engaged in development drilling.Our current development drilling is targeting the Mississippian Lime interval, where we anticipate ultimate development of at least four horizontal wellsper 640 acre section. We are also testing different completion techniques, including selective use of open hole completions, to determine the most costeffective design in this area. During 2013, we invested approximately $315.9 million and drilled 75 horizontal wells in this region; in 2014, we plan to invest approximately$290 million to $330 million in the drilling of between 95 to 105 gross wells, including non-operated wells. Our plans are to continue to activelydevelop this area while evaluating exploration potential beyond our current position.Expansion Areas Within Mississippian All of our rigs currently operating in the Mississippian Lime are focused on infill drilling in our de-risked acreage; however, in the future, we planto run one (or more) rigs in these areas to not only hold acreage but also de-risk the acreage.12 Three MonthsEndedDecember 31,2013 Three MonthsEndedDecember 31,2012 Year EndedDecember 31, 2013 Year EndedDecember 31, 2012(1) Average dailyproduction: Oil (Boe/d) 6,325 2,216 4,567 557 Natural gas liquids(Boe/d) 3,622 1,820 2,620 458 Natural gas (Mcf/day) 45,794 19,021 34,784 4,781 Average dailyproduction (Boe/d) 17,579 7,207 12,985 1,812 (1)Note that as the Eagle Property Acquisition closed on October 1, 2012, this represents the impact to average annual productionfor the period of October 1, 2012 through December 31, 2012.Table of ContentsAnadarko Basin Our Anadarko Basin assets were acquired on May 31, 2013, and at December 31, 2013, consisted of approximately 129,800 net acres in theAnadarko Basin, consisting of 95,500 net acres in Texas and 34,300 net acres in western Oklahoma. We took over operations of the properties onDecember 1, 2013. We currently intend to develop these liquids-rich properties using horizontal wells. Our properties in this area represented 29% of our total proved reserves as of December 31, 2013. As of December 31, 2013, we held an averageworking interest and average net revenue interest of 80% and 53%, respectively, on our acreage in this area. For the quarter ended December 31, 2013 and the period from May 31, 2013 through December 31, 2013, our average daily production from thearea was as follows: During 2013, we invested approximately $96.2 million and drilled 35 horizontal wells; in 2014, we plan to invest approximately $170 million to$210 million in the drilling of between 70 to 75 gross wells, including non-operated wells. Our plans are to continue to actively develop this area whiletesting other potentially productive horizons within our current acreage and expansion areas beyond our current position.Gulf Coast In the Gulf Coast, our current acreage positions and evaluation efforts are concentrated in Louisiana in the Wilcox interval of the Upper Gulf CoastTertiary trend and is characterized by well-defined geology, including tight sands featuring multiple productive zones typically located within largegeologic traps. As of December 31, 2013, we had accumulated approximately 56,500 net acres in the trend and options to acquire an aggregate ofapproximately 24,700 additional targeted net acres. Our development operations in the Gulf Coast area are currently focused on drilling vertical and horizontal wells and commingling productionfrom multi-stage hydraulically fractured completions across stacked oil-producing intervals. As of December 31, 2013, we had drilled 144 wells in thetrend, approximately 92% of which produced commercially, since the third quarter of 2008. Since that time, we have increased our average dailyproduction from 995 Boe/d in the year ended December 31, 2008 to 6,027 Boe/d in the year ended December 31, 2013. Our properties in this area represented 18% of our total proved reserves as of December 31, 2013. As of December 31, 2013, we held an averageworking interest and average net revenue interest of 97% and 73%; respectively, on our acreage in this area.13 Three Months EndedDecember 31, 2013 Year EndedDecember 31, 2013(1) Average daily production: Oil (Boe/d) 3,940 2,239 Natural gas liquids (Boe/d) 1,816 1,082 Natural gas (Mcf/day) 16,190 9,559 Average daily production (Boe/d) 8,454 4,914 (1)Note that as the Anadarko Basin Acquisition closed on May 31, 2013, this represents the impact to average annualproduction for the period of May 31, 2013 through December 31, 2013. No data is available for the respective 2012periods due to the timing of the acquisition.Table of Contents For the quarter ended December 31, 2013 and 2012, and years ended December 31, 2013 and 2012, our average daily production from the areawas as follows: During 2013, we invested approximately $148.9 million for exploration, development and lease and seismic acquisition and drilled 14 wells,including sidetracks, in the Gulf Coast area. In 2014, we currently plan to invest between $5 million and $10 million. We currently have no drilling rigsoperating in this area as we have devoted our capital to developing our Mississippian and Anadarko Basin assets; however, we plan to continue toevaluate our acreage as well as other potential exploration opportunities in the Gulf Coast area. The Gulf Coast areas of operation are concentrated in three core fields in Beauregard and Evangeline Parishes, Louisiana: Pine Prairie, SouthBearhead Creek and North Coward's Gully. In Pine Prairie we spent $31.2 million of capital in 2013, continuing our vertical development of the deeperobjectives in the Wilcox and Sparta with six vertical wells spud during the year. We spent $41.5 million in capital during 2013 in South Bearhead Creekspudding two horizontals and one vertical. Lastly, in 2013, we spent $55.6 million in capital and spud four horizontals, including one sidetrack, in theNorth Coward's Gully field. On March 5, 2014, we executed a PSA to sell all of our ownership interest in developed and undeveloped acreage in the Pine Prairie field area ofEvangeline Parish, Louisiana to a private buyer for a purchase price of $170 million, subject to standard post-closing adjustments. The PSA is expectedto close on May 1, 2014. Acreage subject to the transaction totaled 3,907 gross (3,757 net) acres, and does not include our acreage and production in thewestern part of Louisiana in Beauregard Parish or other undeveloped acreage held outside the Pine Prairie field. Production from the assets included inthis sale averaged 3,453 and 4,777 Boe/d during the years ended December 31, 2013 and 2012, respectively, and 2,366 and 5,361 Boe/d during thefourth quarters ended December 31, 2013 and 2012, respectively. Upon closing of the sale, our remaining Gulf Coast areas of operation will beconcentrated in the South Bearhead and North Coward's Gully fields.14 Three MonthsEndedDecember 31, Year EndedDecember 31, 2013 2012 2013 2012 Average daily production: Oil (Boe/d) 3,375 5,737 3,890 5,162 Natural gas liquids (Boe/d) 995 1,170 1,008 1,228 Natural gas (Mcf/day) 4,706 8,869 6,772 10,778 Average daily production (Boe/d) 5,154 8,385 6,027 8,187 Table of ContentsEstimated Proved Reserves Our proved reserves have grown from 26.2 to 75.5 MMBoe from year end 2011 to year end 2012 and from 75.5 to 127.8 MMBoe from year end2012 to year end 2013. Our reserve growth in these periods is due directly to the extensions and discoveries associated with our drilling activities ineach year and, during 2012, the Eagle Property Acquisition and during 2013, the Anadarko Basin Acquisition. As a result, we have increased ouraverage daily production at a compound annual growth rate of 89% from 995 Boe/d in the year ended December 31, 2008 to 23,927 Boe/d in the yearended December 31, 2013. Our proved undeveloped reserves have grown from 47.7 MMBoe to 79.0 MMBoe from December 31, 2012 to December 31, 2013. During thistime, we spent $249.2 million of our capital expenditures on drilling proved undeveloped locations and converted 11.3 MMBoe from provedundeveloped reserves to proved developed reserves. In addition, we added 43.6 MMBoe of proved15 Oil(MBbl) NGL(MBbl) Gas(MMcf) Total(MBoe) 2011 Proved Reserves Beginning Balance 11,927 314 27,906 16,892 Revision of previous estimates (2,650) 1,661 (6,500) (2,072)Extensions, discoveries and other additions 8,049 2,364 22,204 14,114 Sales of reserves in place — — — — Purchases of reserves in place — — — — Production (1,610) (308) (4,918) (2,738) Net proved reserves at December 31, 2011 15,716 4,031 38,692 26,196 Proved developed reserves, December 31, 2011 6,479 1,802 17,987 11,279 Proved undeveloped reserves, December 31, 2011 9,237 2,229 20,705 14,917 2012 Proved Reserves Beginning Balance 15,716 4,031 38,692 26,196 Revision of previous estimates (1,368) (193) (8,533) (2,982)Extensions, discoveries and other additions 12,262 3,232 32,646 20,935 Sales of reserves in place — — — — Purchases of reserves in place 13,010 7,745 85,293 34,969 Production (2,093) (617) (5,695) (3,659) Net proved reserves at December 31, 2012 37,527 14,198 142,403 75,459 Proved developed reserves, December 31, 2012 13,207 5,437 54,775 27,774 Proved undeveloped reserves, December 31, 2012 24,320 8,761 87,628 47,685 2013 Proved Reserves Beginning Balance 37,527 14,198 142,403 75,459 Revision of previous estimates (13,511) (3,259) (20,762) (20,230)Extensions, discoveries and other additions 17,538 8,812 103,551 43,608 Sales of reserves in place — — — — Purchases of reserves in place 17,242 8,124 73,653 37,642 Production (3,897) (1,719) (18,647) (8,724) Net proved reserves at December 31, 2013 54,899 26,156 280,198 127,755 Proved developed reserves, December 31, 2013 19,853 10,321 111,410 48,743 Proved undeveloped reserves, December 31, 2013 35,046 15,835 168,788 79,012 Table of Contentsundeveloped reserves through extensions and discoveries and had negative revisions of 20.2 MMBoe related to proved undeveloped reserves, of which14.4 MMBoe related to reductions at our Gulf Coast Pine Prairie and West Gordon fields. These net negative revisions in the Gulf Coast were primarilydue to higher development and lease operating costs which resulted in certain proved undeveloped locations becoming uneconomic as of December 31,2013. We also added 37.6 MMBoe of proved reserves, primarily related to the closing of the Anadarko Basin Acquisition. All of our proved undeveloped reserves as of December 31, 2013 are expected to be developed within five years of their initial booking.Independent petroleum engineersMississippian and Gulf Coast Area Reserves Our estimated reserves and related future net revenues at December 31, 2013 for the Mississippian and Gulf Coast areas are based on reportsprepared by Netherland, Sewell & Associates, Inc. ("NSAI"), in accordance with generally accepted petroleum engineering and evaluation principlesand definitions and guidelines in effect during such period established by the SEC. Our estimated reserves and related future net revenues for all areas atDecember 31, 2012 and 2011 were based on reports prepared by NSAI, in accordance with generally accepted petroleum engineering and evaluationprinciples and definitions and guidelines in effect during such period established by the SEC. The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader ofpetroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consultingpetroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarilyresponsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Robert C. Barg and Mr. Philip R. Hodgson.Mr. Barg has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Barg is a Licensed Professional Engineer in the State of Texas(No. 71658) and has over 30 years of practical experience in petroleum engineering, with over 24 years of experience in the estimation and evaluation ofreserves. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Hodgson has beenpracticing consulting petroleum geology at NSAI since 1998. Mr. Hodgson is a Licensed Professional Geoscientist in the State of Texas, Geophysics(No. 1314) and has over 29 years of experience in geological and geophysical studies and evaluations. He graduated from The University of Illinois in1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. All technicalprincipals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oiland Gas Reserves Information promulgated by the Society of Petroleum Engineers; all are proficient in judiciously applying industry standard practicesto engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.Anadarko Area Reserves For our Anadarko area, our estimated reserves and related future net revenues at December 31, 2013 are based on reports prepared by Cawley,Gillespie & Associates, Inc. ("CGA"), in accordance with generally accepted petroleum engineering and evaluation principles and definitions andguidelines in effect during such period established by the SEC. The reserves estimates shown herein have been independently evaluated by CGA, a worldwide leader of petroleum property analysis for industryand financial organizations and government agencies. CGA was founded in 1961 and performs consulting petroleum engineering services under TexasBoard of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forthin the reserves report incorporated herein was16Table of ContentsMr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered ProfessionalEngineer in the State of Texas (License No. 71055) and has over 26 years of practical experience in petroleum engineering, with over 24 years ofexperience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree inPetroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to theEstimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciouslyapplying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions andguidelines.Technology used to establish proved reserves Under Rule 4-10(a)(22) of Regulation S-X, as promulgated by the SEC, proved reserves are those quantities of oil and natural gas, which, byanalysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, fromknown reservoirs, and under existing economic conditions, operating methods, and government regulations. The term "reasonable certainty" implies ahigh degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed 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 byother evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (includingcomputational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability inthe formation being evaluated or in an analogous formation. In order to establish reasonable certainty with respect to our estimated proved reserves, NSAI and CGA employed technologies that have beendemonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reservesinclude, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic dataand well test data.Internal controls over reserves estimation process We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers toensure the integrity, accuracy and timeliness of data furnished to NSAI and CGA in their reserves estimation process. The primary inputs to the reserveestimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technicalinformation, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations andland personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from theCompany's accounting records, which are subject to external quarterly reviews, annual audits and their own set of internal controls over financialreporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials areupdated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. The Company'scurrent ownership in mineral interests and well production data are incorporated into the reserve database as well and verified to ensure their accuracyand completeness. At December 31, 2013, Clifford G. Zwahlen, PE, our former Vice President—Corporate Reserves, was the technical personprimarily responsible for overseeing the preparation of our reserve estimates and reported directly to the CEO. Prior to joining Midstates in March2013, Mr. Zwahlen was the Manager of Reservoir Engineering—Southern Region for Devon Energy, an oil and gas exploration and productioncompany, from November 2011 to February 2013. Prior to that, from September 2009 to October 2011, he was the Reservoir Engineering17Table of ContentsManager and Asset Lead for Devon's Carthage District in East Texas. From February 2008 to August 2009, Mr. Zwahlen was the Director of theProject Management Office for Devon's Shared Services Group and from March 2005 to February 2008 he held the position of Manager of CorporatePlanning for Devon's Exploration and Production Business Unit. He also held management and engineering positions with EOG Resources andPetroCorp, Inc. Mr. Zwahlen currently serves on the Advisor Board for the MPGE School of the University of Oklahoma and the PetroleumEngineering Industry Board at Texas A&M University. He holds a degree in Petroleum Engineering from Texas A&M University and is a registeredProfessional Engineer in the state of Texas (License No. 76924). Throughout each fiscal year, our technical team meets with representatives of ourindependent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. Whilewe have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the reservereport is reviewed by our senior management with representatives of our independent reserve engineers and internal technical staff. In connection with our annual evaluation of the effectiveness of our internal control over financial reporting, we determined that, as ofDecember 31, 2013, we did not maintain effective internal control over the accuracy and valuation of oil and gas reserves estimates. Specifically,controls were not operating effectively over the validation of the accuracy and completeness of certain source data provided to the independent thirdparty reserve engineers. We also did not perform adequate management review of the independent third party reserves reports to determine if reservesestimates were complete and consistent with management's capital spending plans. These control deficiencies resulted in errors that, if not corrected,would have resulted in the misstatement of disclosures related to the value of oil and gas properties and associated reserve estimates. Please see"Management's Annual Report on Internal Control Over Financial Reporting" in Item 9A of this Annual Report.Production, revenues and price history Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply anddemand. Demand for oil and natural gas in the United States has increased dramatically during the past decade. However, the current economicslowdown during the second half of 2008 and through 2009 reduced this demand. Demand for oil increased during 2010, 2011 and 2012, but demandfor natural gas has remained sluggish. Additionally, the price of natural gas has remained relatively depressed due to increasing supplies from shaleplays, but has increased in recent months due to shortages caused by severe winter weather. Demand is impacted by general economic conditions,weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial pricevolatility. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. A substantial or extended decline in oilor natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities ofoil and natural gas reserves that may be economically produced and our ability to access capital markets. The following table sets forth informationregarding oil, natural gas liquids and natural gas production, revenues and realized prices and production costs for the years ended December 31, 2013,2012 and18Table of Contents2011. For additional information on price calculations, see information set forth in "Management's Discussion and Analysis of Financial Condition andResults of Operation."19 Years Ended December 31, 2013 2012 2011 Operating Data: Net production volumes: Oil (MBbls) 3,904 2,093 1,610 NGLs (MBbls) 1,719 617 308 Natural gas (MMcf) 18,657 5,695 4,918 Total oil equivalents (MBoe) 8,733 3,659 2,737 Average daily production (Boe/d) 23,927 9,999 7,499 Average Sales Prices: Oil, without realized derivatives (per Bbl) $99.18 $104.35 $110.25 Oil, with realized derivatives (per Bbl) $93.41 $95.05 $99.85 Natural gas liquids, without realized derivatives (per Bbl) $36.26 $38.27 $50.98 Natural gas liquids, with realized derivatives (per Bbl) $37.09 $40.48 (a) Natural gas, without realized derivatives (per Mcf) $3.39 $2.81 $4.20 Natural gas, with realized derivatives (per Mcf) $3.58 $3.21 (a) Costs and Expenses (per Boe of production): Lease operating and workover $8.41 $8.34 $5.89 Gathering and transportation $0.62 $— $— Severance and other taxes $3.12 $6.81 $4.98 Asset retirement accretion $0.17 $0.20 $0.12 Depreciation, depletion and amortization $28.67 $34.32 $33.50 Impairment of oil and gas properties $51.91 $— $— General and administrative $6.10 $8.35 $25.18 Acquisition and transaction costs $1.35 $4.07 $— Other $0.07 $— $— (a)We did not have any hedges in place on our natural gas or NGL production prior to October 1, 2012.Table of Contents The following table sets forth information regarding oil, NGLs and natural gas production for each of the fields that represented more than 15% ofour estimated total proved reserves as of December 31, 2013:Productive Wells The following table presents our total gross and net productive wells as of December 31, 2013: Gross wells are the number of wells in which a working interest is owned, and net wells are the total of our fractional working interest owned ingross wells.Acreage The following table sets forth certain information regarding the developed and undeveloped acreage in which we have a controlling interest as ofDecember 31, 2013 for each of our operating areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from thissummary.20 Years EndedDecember 31, 2013 2012 2011 Mississippian(1) Net production volumes: Oil (MBbls) 4,550 203 — NGLs (MBbls) 1,908 123 — Natural gas (MMcf) 30,070 1,289 — Total oil equivalents (MBoe) 11,470 541 — Anadarko(2) Net production volumes: Oil (MBbls) 2,239 — — NGLs (MBbls) 1,082 — — Natural gas (MMcf) 9,559 — — Total oil equivalents (MBoe) 4,914 — — (1)These volumes represent only Mississippian Lime production and do not include Hunton volumes. (2)Anadarko volumes include production from May 31, 2013, the date of acquisition of the Anadarko Basin Properties,through December 31, 2013. Oil Natural Gas Total Gross Net Gross Net Gross Net Total productive wells 617 463 105 79 722 542 Developed Acres Undeveloped Acres Total Acres Gross Net Gross Net Gross Net Mississippian 94,287 61,843 43,248 35,316 137,535 97,159 Anadarko Basin 102,992 82,783 58,541 47,054 161,533 129,837 Gulf Coast 16,326 16,313 67,061 64,899 83,387 81,212 Total 213,605 160,939 168,850 147,269 382,455 308,208 Table of ContentsUndeveloped Acreage Expirations The following table sets forth the number of gross and net undeveloped acres as of December 31, 2013 that will expire over the next three years byoperating area unless production is established within the spacing units covering the acreage or we make additional lease rental payments prior to theexpiration dates: Excluding the Anadarko Basin Acquisition, approximately 12% of our net acreage, including acreage under option, was acquired in 2013, with themajority of such leases under three year primary term leases. In addition, our typical lease terms along with unit regulatory rules generally provide usflexibility to continue lease ownership through either establishing production or actively drilling prospects.Drilling Activity The following table summarizes our drilling activity for the years ended December 31, 2013, 2012 and 2011. Gross wells reflect the sum of allwells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. As of December 31, 2013, no exploratory wells were being drilled and seven gross (and net) development wells were currently drilling. Our drilling activity has increased over the last three years, and we were operating ten drilling rigs on our properties as of December 31, 2013. Ourrecent drilling activity has primarily focused on development and delineation and appraisal of our primary operating areas in the Mississippian andAnadarko Basin. In addition to the drilling activity listed above, a portion of our capital program over the last three years has also been focused on re-entering and recompleting productive zones in existing wellbores. In 2013 we had a total of three gross (and net) that were deemed dry hole wells, twoof which were geologic dry holes and one of which was caused by mechanical problems encountered while drilling which prevented us from reachingthe reservoir targets.21 Expiring 2014 Expiring 2015 Expiring 2016 Gross Net Gross Net Gross Net Mississippian 28,203 20,046 4,945 4,543 9,594 8,990 Anadarko Basin 39,861 32,039 13,578 8,066 11,696 6,949 Gulf Coast 1,914 1,875 3,738 3,537 33,235 32,318 Total Undeveloped Acreage Expirations 69,978 53,960 22,261 16,146 54,525 48,257 Years Ended December 31, 2013 2012 2011 Gross Net Gross Net Gross Net Development wells: Productive 121 98 68 64 29 29 Dry holes 1 1 7 7 — — Total 122 99 75 71 29 29 Exploratory wells: Productive — — 4 3 2 2 Dry holes 2 2 — — — — Total 2 2 4 3 2 2 Total wells 124 101 79 74 31 31 Table of ContentsMarketing and Major Customers We sell our oil, natural gas liquids and natural gas to third-party purchasers. We are not dependent upon, or contractually limited to, any onepurchaser or small group of purchasers other than in our Mississippian region where a portion of our natural gas production is dedicated to onepurchaser for the economic life of the relevant assets. For the year ended December 31, 2013, ConocoPhillips, Chevron, Gulfmark, Semgas and ValeroMarketing accounted for 28%, 16%, 13%, 12%, and 11% of our revenues, respectively. For the year ended December 31, 2012, Chevron, Gulfmarkand Targa accounted for 41%, 32% and 10% of our revenues, respectively. For the year ended December 31, 2011, Chevron and Gulfmark accountedfor 39% and 38% of our revenues, respectively. Due to the nature of oil, natural gas and NGL markets, and because we sell our oil production topurchasers that transport by truck rather than by pipelines, we do not believe the loss of a single purchaser or a few purchasers would materiallyadversely affect our ability to sell our production.Title to Properties As is customary in the oil and natural gas industry, we initially conduct a cursory review of the title to our properties on which we do not haveproved reserves. Prior to the commencement of drilling operations on those properties, we conduct a more thorough title examination and performcurative work with respect to significant defects. To the extent title opinions or other investigations reflect defects affecting those properties, we aretypically responsible for curing any such defects at our expense. We generally will not commence drilling operations on a property until we have curedknown material title defects on such property. We have reviewed the title to substantially all of our producing properties and believe that we havesatisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing anacquisition of producing oil and natural gas properties, we perform title reviews on the most significant properties and, depending on the materiality ofproperties, we may obtain a title opinion or review or update previously obtained title opinions. Our oil and natural gas properties are subject tocustomary royalty and other interests, liens to secure borrowings under our credit facility, liens for current taxes and other burdens which we believe donot materially interfere with their use or affect our carrying value of the properties.Seasonality Generally, demand for oil and natural gas decreases during the spring and fall months and increases during the summer and winter months.However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilizenatural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demandfluctuations. Winter weather conditions can limit or temporarily halt our drilling and producing activities and other oil and natural gas operations, including gasprocessing, access to electricity and transportation. Additionally, once production comes back online following a cessation due to weather, it may take aperiod of time before production from a well reaches the level it was at prior to the cessation. These constraints and the resulting shortages or high costscould delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challengesfor 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.22Table of ContentsCompetition The oil and natural gas industry is highly competitive. We compete with numerous entities, including major domestic and foreign oil companies,other independent oil and natural gas companies and individual producers and operators. Many of these competitors are large, well establishedcompanies and have financial and other resources substantially greater than ours. Our ability to acquire additional oil and natural gas properties and todiscover reserves in the future will depend upon our ability to evaluate and select suitable properties and successfully consummate transactions in ahighly competitive environment.Regulation of the oil and natural gas industry Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and relatedoperations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own oroperate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas,including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method ofdrilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drillingand completion process and produced during operations and the abandonment of wells. Our operations are also subject to various conservation lawsand regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area,and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and imposecertain requirements regarding the ratability or fair apportionment of production from fields and individual wells. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the costof doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, and thatcontinued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results ofoperations, such laws and regulations are frequently amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur orpast non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact ofcompliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, theFederal Energy Regulatory Commission ("FERC") and the courts. We cannot predict when or whether any such proposals may become effective.Regulation of transportation and sale of oil Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress couldreenact price controls in the future. The price we receive from the sale of these products may be affected by the cost of transporting the products tomarket. For our oil production, all of that transportation is currently via truck and we do not rely on interstate or intrastate pipelines.Regulation of transportation and sales of natural gas Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the Federal Energy RegulatoryCommission ("FERC") under the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and regulations issued underthose statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While23Table of Contentssales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellheadnatural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed allprice 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 weproduce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation moreaccessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary toimprove the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers intomore direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation andstorage services. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As aresult, the interstate pipelines' traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replacedby a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas.Although the FERC's orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of thenatural gas industry. In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competitionin natural gas markets. Among other things, Order No. 637 revised the FERC's pricing policy by waiving price ceilings for short-term released capacityfor a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rightsof first refusal and information reporting. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatoryapproach recently established by the FERC under Order No. 637 will continue. However, we do not believe that any action taken will affect us in a waythat materially differs from the way it affects other natural gas producers. The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation.However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and relatedregulations enforced by the FERC and/or the Commodity Futures Trading Commission ("CFTC") and the Federal Trade Commission ("FTC"). Shouldwe violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers,royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to FERC onMay 1 of each year for the previous calendar year. Order No. 704 requires certain natural gas market participants to report information regarding theirreporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale,physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters.Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictionaltransmission function, the FERC's determinations as to the classification of facilities is done on a case by case basis. State regulation of natural gasgathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although suchregulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.Intrastate natural gas transportation and facilities are24Table of Contentsalso subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC.The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipelinerates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shipperswithin the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which weoperate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce,as well as the revenues we receive for sales of our natural gas.Regulation of production The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the statesin which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil andnatural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, andplugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells andto limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in wellspacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gasliquids within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry aresubject to the same regulatory requirements and restrictions that affect our operations.Other federal laws and regulations affecting our industry Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 ("EPAct 2005"). EPAct 2005 is acomprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policythat affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision whichmakes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civilpenalty authority. EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA andincreases the FERC's civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. The civil penaltyprovisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued OrderNo. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for anyentity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale oftransportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statementof material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act, practice, or courseof business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate orother non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such asSection 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases ortransportation subject to FERC jurisdiction,25Table of Contentswhich now includes the annual reporting requirements under Order No. 704. The anti-manipulation rules and enhanced civil penalty authority reflect anexpansion of FERC's NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, andorders, we could be subject to substantial penalties and fines. FERC Market Transparency Rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reportingrequirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers,natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gaspurchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of priceindices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of OrderNo. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether theirreporting 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 marketmanipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil,gasoline or petroleum distillates at wholesale from: (a) knowingly engaging in any act, practice or course of business, including the making of anyuntrue 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 factthat under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort marketconditions for any such product. A violation of this rule may result in civil penalties of up to $1.0 million per day per violation, in addition to anyapplicable penalty under the Federal Trade Commission Act. Additional proposals and proceedings that might affect the oil and natural gas industry are pending before Congress, FERC and the courts. Wecannot predict the ultimate impact of these or the above regulatory changes to our operations. We do not believe that we would be affected by any suchaction materially differently than similarly situated competitors.Environmental and occupational health and safety regulation Our oil and natural gas exploration, development and production operations are subject to stringent and complex federal, regional, state and locallaws and regulations governing occupational safety and health, the emission or discharge of materials into the environment and environmentalprotection. Numerous governmental entities, including the U.S. Environmental Protection Agency ("EPA"), analogous state agencies, and, in certaininstances, citizens' groups, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiringdifficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and otherregulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected intoformations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying withinwilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such asrequirements to close waste pits and plug abandoned wells; (v) impose specific safety and health criteria addressing worker protection; and (vi) imposesubstantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result inthe assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations and the issuance of injunctionsprohibiting some or all of our operations. These laws and regulations may also restrict the rate of oil and natural gas production below the rate thatwould26Table of Contentsotherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequentlyaffects profitability. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, anychanges in federal or state environmental laws and regulations or re-interpretation of applicable enforcement policies that result in more stringent andcostly well construction, drilling, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirementsor that limit or otherwise restrict the emission of certain pollutants or organic compounds from wells or surface equipment could have a material adverseeffect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidentalreleases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result ofsuch releases or spills, including any third party claims for damage to property, natural resources or persons. While we believe that we are in substantialcompliance 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 withexisting or any new laws and regulations or that future compliance with such laws and regulations will not have a material adverse effect on ourbusiness and operating results. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our businessoperations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financialposition.Hazardous substances and wastes The Comprehensive Environmental Response, Compensation, and Liability Act, as amended ("CERCLA"), also known as the Superfund law, andcomparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered tobe responsible for the release of a "hazardous substance" into the environment. These classes of persons include current and prior owners or operatorsof the site where the release occurred and entities that disposed of or arranged for the disposal of the hazardous substances at a site where a release hasoccurred. Under CERCLA, these "responsible parties" may be subject to strict, joint and several liability for the costs of removing and cleaning up thehazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies.CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek torecover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to fileclaims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment.Despite the "petroleum exclusion" of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handlehazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointlyand severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into theenvironment. We also are subject to the requirements of the Resource Conservation and Recovery Act, as amended ("RCRA"), and comparable state statutes.RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes and nonhazardous solidwastes. Under the authority of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, morestringent requirements. Although RCRA currently exempts certain drilling fluids, produced waters, and other wastes associated with exploration,development and production of oil and natural gas from regulation as hazardous wastes, we can27Table of Contentsprovide no assurance that this exemption will be preserved in the future. From time to time the EPA and analogous state agencies have consideredrepealing or modifying this exemption, and citizens' groups have also petitioned the agency consider its repeal. Repeal or modification of this exemptionor similar exemptions under state law could have a significant impact on our operating costs as well as the oil and natural gas industry in general. Theimpact of future revisions to environmental laws and regulations cannot be predicted. In any event, at present, these excluded wastes are subject toregulation as nonhazardous solid wastes. In addition, we generate petroleum hydrocarbon wastes and ordinary industrial wastes in the course of ouroperations that may become regulated as hazardous wastes if such wastes have hazardous characteristics. 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 andnatural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons andwastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these petroleumhydrocarbons and wastes have been taken for recycling or disposal. In addition, certain of these properties have been operated by the third partieswhose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and wastes disposedthereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previouslydisposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminatedgroundwater) and to perform remedial operations to prevent future contamination.Air emissions The Clean Air Act, as amended ("CAA"), and comparable state laws, regulate emissions of various air pollutants through air emissions standards,construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us toobtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtainand strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Theneed to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incurcertain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in August 2012, the EPA publishedfinal rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NewSource Performance Standards ("NSPS") and National Emission Standards for Hazardous Air Pollutants ("NESHAP") programs. With regards toproduction activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories offractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoirpressure non-wildcat and non-delineation gas wells; and all "other" fractured and refractured gas wells. All three subcategories of wells must route flowback emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 2012. However, the "other"wells must use reduced emission completions, also known as "green completions," with or without combustion devices, beginning in January 2015.These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors andfrom pneumatic controllers and storage vessels. We continue to review these rules and assess their potential impacts on our operations. Compliance withthese requirements could increase our costs of development and production, which costs could be significant.28Table of ContentsClimate change Recent scientific studies have suggested that emissions of certain greenhouse gases ("GHGs"), which include carbon dioxide and methane, may becontributing to warming of the earth's atmosphere and other climatic changes. In December 2009, the EPA published its findings that emissions ofgreenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA,contributing to the warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existingprovisions of the federal Clean Air Act that establish pre-construction and operating permitting requirements for GHG emissions from certain largestationary sources. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the UnitedStates, including, among others, certain oil and natural gas production facilities on an annual basis, which includes certain of our operations. We aremonitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are insubstantial compliance with applicable reporting obligations. In addition, in August 2012, the EPA established new source performance standards forvolatile organic compounds and sulfur dioxide and an air toxic standard for oil and natural gas production, transmission, and storage activities. The rulesinclude the first federal air standards for natural gas wells that are hydraulically fractured, or refractured, as well as requirements for several othersources, such as storage tanks and other equipment, and limits methane emissions from these sources in an effort to reduce GHG emissions. TheseEPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. We cannot predictwhich areas, if any, the EPA may choose to regulate with respect to GHG emissions next. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form ofadopted legislation to reduce GHG emissions at the federal level in recent years. If Congress undertakes comprehensive tax reform in the coming year, itis possible that such reform may include a carbon tax, which could impose additional direct costs on our operations and the industry in general.Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact ourbusiness, such requirements could require us to obtain permits for our GHG emissions, install costly emission controls, and adversely affect demandfor the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in theEarth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts andfloods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.Water discharges The Federal Water Pollution Control Act, as amended (the "Clean Water Act"), and analogous state laws impose restrictions and strict controlsregarding the discharge of pollutants into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited,except in accordance with the terms of a permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasurerequirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in theevent of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits orcoverage under general permits for discharges of storm water runoff from certain types of facilities, including oil and natural gas production facilities.The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit.Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for29Table of Contentsnoncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. The Oil Pollution Act of 1990, as amended ("OPA"), amends the Clean Water Act and sets minimum standards for prevention, containment andcleanup of oil spills. The OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affectwaters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be held strictly liable for oilcleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requiresowners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of theUnited States.Hydraulic fracturing activities Hydraulic fracturing is an important and common industry practice that is used to stimulate production of natural gas and/or oil from densesubsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targetedsubsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of ourdrilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federalregulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels andpublished draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPAannounced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding thechemicals used in hydraulic fracturing; however, to date, the agency has taken no action to do so. In addition, Congress has from time to timeconsidered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to requiredisclosure of the chemicals used in the hydraulic fracturing process. Some states, including Louisiana, Texas and Oklahoma, where we operate, haveadopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well constructionrequirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, placeand manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industrypractices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nevertheless, if new or more stringent federal, state orlocal legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant addedcosts to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, andperhaps even be precluded from drilling wells. In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturingpractices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPAhas commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress reportoutlining work currently underway by the agency released in December 2012 and a final report expected to be available for public comment and peerreview sometime in 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewaterresulting from hydraulic fracturing activities sometime in 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S.Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These studies, depending on their degree ofpursuit and any meaningful results obtained, could spur initiatives30Table of Contentsto further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms. To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We onlyuse qualified contractors to perform hydraulic fracturing activities at our properties who have experience performing fracturing services on similarproperties and who have demonstrated to our satisfaction that they employ appropriate safeguards to ensure that hydraulic fracturing will be performedin a safe and environmentally protective manner. We do not have insurance policies in effect that are intended to provide coverage for losses solelyrelated to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claimsrelated to hydraulic fracturing operations conducted by third parties and associated legal expenses in accordance with, and subject to, the terms andcoverage limits of such policies.Endangered Species Act considerations The federal Endangered Species Act, as amended ("ESA"), restricts exploration, development and production activities that may affect endangeredand threatened species or their habitats. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened orendangered in the United States, and prohibits the taking of endangered species. Federal agencies are required to insure that any action authorized,funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitats. While some of ourfacilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliancewith the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activitiesor abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlementapproved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to make adetermination on a listing of more than 250 species as endangered or threatened under the ESA over the next six years, through the agency's 2017 fiscalyear. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted couldcause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities thatcould have an adverse impact on our ability to develop and produce reserves.OSHA We are subject to the requirements of the federal Occupational Safety and Health Act, as amended ("OSHA"), and comparable state statutes whosepurpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and CommunityRight-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information abouthazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities andcitizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.Employees As of December 31, 2013, we employed 217 people, including 56 technical (geosciences, engineering, land), 100 field operations, 52 corporate(finance, accounting, planning, business development, legal, office management) and nine management.31Table of ContentsOffices We currently lease approximately 41,200 square feet of office space in Houston, Texas at 4400 Post Oak Parkway, Suite 1900, where ourprincipal offices are located. The lease for our Houston office expires in 2018. We also lease two field offices in Louisiana, one in Perryton, Texas andapproximately 57,000 square feet of office space in Tulsa, Oklahoma at 321 South Boston Avenue, Suite 600. The lease for our Tulsa office expires in2021.Available Information We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy anydocuments filed by us with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain informationon the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public fromcommercial document retrieval services and at the SEC's website at http://www.sec.gov. Our common stock is listed and traded on the New York Stock Exchange under the symbol "MPO." 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 (http://www.midstatespetroleum.com) all of the documents that we file with the SEC, free of charge, assoon as reasonably practicable after we electronically file such material with the SEC. Our Code of Business Conduct and Ethics, CorporateGovernance Guidelines, Financial Code of Ethics, and the charters of our audit committee, compensation committee and nominating and governancecommittee are also available on our website and in print free of charge to any stockholder who requests them. Requests should be sent by mail to 4400Post Oak Parkway, Suite 1900; Houston, Texas 77027, attention Corporate Counsel. Information contained on our website is not incorporated byreference into this Annual Report on Form 10-K. We intend to disclose on our website any amendments or waivers to our Code of Ethics that arerequired to be disclosed pursuant to Item 5.05 of Form 8-K.ITEM 1A. RISK FACTORS Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K inour other public filings, press releases and discussions with our management actually occurs, our business, financial condition or results ofoperations could suffer. The risks described below are the known material risk factors facing us. Additional risks not presently known to us or whichwe currently consider immaterial also may adversely affect us.Risks Related to the Oil and Gas Industry and Our BusinessA substantial or extended decline in oil and, to a lesser extent, natural gas, prices may adversely affect our business, financial condition or resultsof 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 ofgrowth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes insupply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future.The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include thefollowing:•worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;32Table of Contents•the actions of the Organization of Petroleum Exporting Countries; •the price and quantity of imports of foreign oil and natural gas; •political conditions in or affecting other oil and natural gas-producing countries; •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 transportation availability; •weather conditions and natural disasters; •domestic, local and foreign governmental regulations and taxes; •speculation as to the future price of oil and natural gas 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 currently sold to purchasers under short-term (less than 12-month) contracts at market based prices. Lower oiland natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. If oil and natural gas prices deteriorate, weanticipate that the borrowing base under our revolving credit facility, which is revised periodically, may be reduced. Lower oil and natural gas pricesmay also reduce the amount of oil and natural gas that we can produce economically. Substantial decreases in oil and natural gas prices could renderuneconomic a significant portion of our identified drilling locations. This may result in our having to make significant downward adjustments to ourestimated proved reserves. As a result, a substantial or extended decline in oil or natural gas prices may materially and adversely affect our futurebusiness, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financialcondition or results of operations. Our future financial condition and results of operations will depend on the success of our development, drilling and production activities. Our oiland natural gas drilling and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result incommercially viable oil or natural gas production. Our decisions to purchase, explore or develop drilling locations or properties will depend in part onthe evaluation of data obtained through 2D and 3D seismic data, geophysical and geological analyses, production data and engineering studies, theresults of which are often inconclusive or subject to varying interpretations. The production and operating data that is available with respect to ouroperating areas based on modern drilling and completion techniques is relatively limited compared to trends where multiple operators have been activefor a significant period of time. As a result, we face more uncertainty in evaluating data than operators in more developed trends. For a discussion of theuncertainty involved in these processes, see "—Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Anysignificant inaccuracies in these assumptions will materially affect the quantities and present value of our reserves." Our costs of drilling, completingand operating wells are often uncertain before drilling commences. In addition, the application of new techniques in these trends, such as high-gradedstimulation designs and horizontal completions, some of which we may not have previously employed, may make it more difficult to accurately estimatethese costs. Overruns in budgeted expenditures are33Table of Contentscommon 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; •unexpected operational events; •pressure or irregularities in geological formations; •adverse weather conditions; •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. In addition, our hydraulic fracturing operations require significant quantities of water. Regions where we operate have recently experienceddrought conditions. These conditions could persist in the future, diminishing our access to water for hydraulic fracturing operations. Any diminishedaccess to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail our operations orotherwise result in delays in operations or increased costs.The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of ourestimated oil and natural gas reserves. You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value ofour estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2013, 2012 and 2011, we based thediscounted future net cash flows from our proved reserves on the 12-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 cash flows from our oil and natural gas properties will beaffected by factors such as:•actual prices we receive for oil and natural gas; •actual cost of development and production expenditures; •the amount and timing of actual production; and •changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gasproperties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10%discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from timeto time and risks associated with us or the oil and natural gas industry in general. Prior to our corporate reorganization in April 2012 in connection withour initial public offering, we were not subject to entity level taxation. Accordingly, our standardized measure for periods prior to such reorganizationdoes not provide for federal or state corporate income taxes because taxable income was passed through to our equity holders. However, as a result ofour corporate reorganization, we are now treated as a taxable entity for federal income tax purposes and our income taxes are dependent upon ourtaxable income. Actual future prices and costs34Table of Contentsmay differ materially from those used in the present value estimates included in this report which could have a material effect on the value of ourreserves.If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties. We usethe full cost method of accounting for our oil and gas properties. Accordingly, we capitalize and amortize all productive and nonproductive costs directly associated with property acquisition, exploration anddevelopment activities. Under the full cost method, the capitalized cost of oil and gas properties, less accumulated amortization and related deferredincome taxes may not exceed the "cost center ceiling" which is equal to the sum of the present value of estimated future net revenues from provedreserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%,plus the costs of properties not subject to amortization, plus the lower of the cost or estimated fair value of unproved properties included in the costsbeing amortized, less related income tax effects. If the net capitalized costs exceed the cost center ceiling, we recognize the excess as an impairment of oiland gas properties. At December 31, 2013, we recognized an impairment of $319.6 million, net of taxes, for the amount by which our net capitalizedcosts exceeded the cost center ceiling. This impairment does not impact cash flows from operating activities but does reduce our earnings andshareholders' equity. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of lowcommodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves orthe present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higheroil and gas prices increase the cost center ceiling applicable to the subsequent period. We could incur impairments of oil and natural gas properties in thefuture, particularly as a result of a decline in commodity prices.Our level of indebtedness may increase and reduce our financial flexibility. As of December 31, 2013, we had $99 million available and a borrowing base of $500 million under our revolving credit facility, $600 million in2020 Senior Notes and $700 million in 2021 Senior Notes outstanding. In the future, we may incur significant additional indebtedness in order to makefuture acquisitions or to develop our properties. Our current level of indebtedness could affect our operations in several ways, including the following:•causing a significant portion of our cash flows to be used to service our indebtedness, thereby reducing the availability of cash flows forworking capital, capital expenditures and other general business activities; •increasing our vulnerability to general adverse economic and industry conditions; •limiting our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; •placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, such competitors may be ableto take advantage of opportunities that our indebtedness would prevent us from pursuing; •causing our debt covenants to affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; •making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion ofour then outstanding bank borrowings;35Table of Contents•impairing our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporateor other purposes; and •making it more difficult for us to satisfy our obligations under the indentures governing our Senior Notes. 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 reduceour level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and otherfactors affect our operations and our future performance. Many of these factors are beyond our control. If we are unable to repay our debt out of our cash on hand, we could attempt to refinance such debt, obtain additional borrowings, sell assets orrepay such debt with the proceeds from an equity offering. We cannot assure you that refinancing, additional borrowings, proceeds from the sale ofassets or equity financing will be available to pay or refinance such debt. Factors that may affect our ability to raise cash through an offering of ourcapital stock, a refinancing of our debt or a sale of assets include financial market conditions, our market value, our reserve levels and our operatingperformance at the time of such offering or other financing. The inability to repay or refinance our debt could have a material adverse effect on ouroperations and could result in a reduction in our capital program or lead us to pursue other alternatives to develop our assets. In addition, our bank borrowing base is subject to periodic redeterminations on a semi-annual basis, effective October 1 and April 1 and up to oneadditional time per six-month period following each scheduled borrowing base redetermination, as may be requested by either us or the administrativeagent under our revolving credit facility. In the future we could be forced to repay a portion of our then outstanding bank borrowings due to futureredeterminations 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 havesufficient funds and are unable to arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect onour business and financial results.We have incurred losses from operations during certain periods since the beginning of 2008 and may continue to do so in the future. We incurred losses from operations of $407.4 million, $15.6 million and $11.8 million for the years ended December 31, 2013, 2010 and 2009,respectively. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to requiresubstantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically acquire and develop 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 thefuture.Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in theseassumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions,including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these assumptionscould materially affect the estimated quantities and present value of reserves shown in this report. See "Summary of Oil and Gas Properties andOperations" for information about our estimated oil and natural gas reserves. In order to prepare our estimates, we must estimate production rates and the timing of development expenditures. We must also analyze availablegeological, geophysical, production and36Table of Contentsengineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil andnatural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Estimates of oil and natural gas reserves areinherently imprecise. In addition, reserve estimates for properties that do not have a lengthy production history, including the areas in which we operate,are less reliable than estimates for fields with lengthy production histories. There can be no assurance that analysis of previous production data relatingto the Mississippian Lime, Anadarko Basin or Upper Gulf Coast Tertiary trend will accurately predict future production, development expenditures oroperating expenses from wells drilled and completed using modern techniques. In addition, this data is partially based on vertically drilled wells, whichmay not accurately reflect production, development expenditures or operating expenses that may result from the application of horizontal drillingtechniques. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverableoil and natural gas reserves may vary from our estimates. Any significant variance could materially affect the estimated quantities and present value ofreserves shown in this report. In addition, we may adjust estimates of 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.The development of our proved undeveloped reserves in our areas of operation may take longer and may require higher levels of capitalexpenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced. Approximately 62% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2013. Development of thesereserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves orincreases in costs to drill and develop such reserves will reduce the future net revenues estimated for such reserves and may result in some projectsbecoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify proved reserves as unproved reserves.Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financialcondition and results of operations. Unless we conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves willdecline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that varydepending 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 our current reserves and economically finding or acquiring additional recoverablereserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we areunable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results ofoperations will be adversely affected.Drilling locations that we have identified may not yield oil or natural gas in commercially viable quantities. We describe some of our drilling locations and our plans to explore those drilling locations in this report. Our drilling locations are in variousstages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way topredict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling orcompletion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to knowconclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be37Table of Contentspresent in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productivehydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from orabandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success ratemay decline and materially harm our business. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may notbe productive.Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter theoccurrence or timing of their drilling, which in certain instances could prevent production prior to the expiration date of leases for such locations.In addition, we may not be able to raise the amount of capital that would be necessary to drill a substantial portion of our identified drillinglocations. Our management team has identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on ourexisting acreage and acreage currently under option. These drilling locations represent a significant part of our growth strategy. Our ability to drill anddevelop these drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling andproduction costs, the availability of drilling services and equipment, drilling results, lease expirations, gathering systems, marketing and pipelinetransportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locationswe have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other drilling locations. In addition, unlessproduction is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases forsuch acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.Part of our strategy involves using some of the latest available horizontal drilling and completion techniques. The results of our horizontal drillingactivities are subject to drilling and completion technique risks, and actual drilling results may not meet our expectations for reserves orproduction. As a result, we may incur material impairment of the carrying value of our unevaluated properties, and the value of our undevelopedacreage could decline if drilling results are unsuccessful. Risks that we face while horizontally drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desireddrilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and otherequipment consistently through the horizontal well bore. Risks that we face while completing our horizontal wells include, but are not limited to, beingable to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations andsuccessfully cleaning out the well bore after completion of the final fracture stimulation stage. Ultimately, the success of these horizontal drilling andcompletion techniques can only be evaluated over time as more wells are drilled in the Mississippian Lime, Anadarko Basin and Upper Gulf CoastTertiary trend and production profiles are established over a sufficiently long time period. If our horizontal drilling results in these trends are less thananticipated, the return on our investment in this area may not be as attractive as we anticipate. The carrying value of our unevaluated properties couldbecome impaired, which would increase our depletion rate per Boe or result in a ceiling test impairment if there were no corresponding additions torecoverable reserves, and the value of our undeveloped acreage in this area could decline in the future.38Table of ContentsThe unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability toexecute our exploration and development plans within our budget and on a timely basis. We utilize third-party services to maximize the efficiency of our organization. The cost of oilfield services may increase or decrease depending onthe demand for services by other oil and gas companies. There is no assurance that we will be able to contract for such services on a timely basis or thatthe cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of frac crews, drilling rigs, equipment, supplies,personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expendituresthat are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.Our business depends on transportation by truck for our oil and condensate production, and our natural gas production depends ontransportation facilities that are owned by third parties. We transport all of our oil and condensate production by truck, which is more expensive and less efficient than transportation via pipeline. Ournatural gas production depends in part on the availability, proximity and capacity of pipeline systems and processing facilities owned by third parties.Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipelinepressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oiland natural gas. The disruption of third-party facilities due to maintenance or weather could negatively impact our ability to market and deliver our products. Wehave no control over when or if such facilities are restored or what prices will be charged. A total shut-in of production could materially affect us due toa lack of cash flows, and if a substantial portion of the production is hedged at lower than current market prices, those financial hedges would have to bepaid from borrowings absent sufficient cash flows.Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation,pipelines, gas gathering, transmission, storage and processing facilities to market our oil and gas production. The marketing of oil and gas production depends in large part on the capacity and availability of trucks, pipelines and storage facilities, gasgathering systems and other transportation, processing and refining facilities. Access to such facilities is, in many respects, beyond our control. If thesefacilities were unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinuedrilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect to rely in the future) on facilities developed andowned by third parties in order to store, process, transmit and sell our oil and gas production. Our plans to develop and sell our oil and gas reservescould be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us oncommercially reasonable terms or otherwise. The amount of oil and gas that can be produced is subject to limitation in certain circumstances, such aspipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, transportation, refining orprocessing facilities, or lack of capacity on such facilities. The curtailments arising from these and similar circumstances may last from a few days toseveral months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.39Table of ContentsWe may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally we maynot be insured for, or our insurance may be inadequate to protect us against, these risks. We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect ourbusiness, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risksassociated with drilling for and producing oil and natural gas, including the possibility of:•environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into theenvironment, including groundwater contamination; •abnormally pressured formations; •mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; •fires, explosions and ruptures of pipelines; •personal injuries and death; and •natural disasters. Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:•injury or loss of life; •damage to and destruction of property, natural resources and equipment; •pollution and other environmental damage; •regulatory investigations and penalties; •suspension of our operations; and •repair and remediation costs. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition,pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have amaterial adverse effect on our business, financial condition and results of operations.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, or increases in interest rates.Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to drill ouridentified locations and pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recentdisruptions and continuing volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availabilityimpacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit couldmaterially and adversely affect our ability to achieve our planned growth and operating results.40Table of ContentsOur revolving credit facility and the indentures governing our Senior Notes contains certain covenants that may inhibit our ability to make certaininvestments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our futuregoals. Our revolving credit facility and the indentures governing our Senior Notes includes certain covenants that, among other things, restrict:•our ability to incur or assume additional debt or provide guarantees in respect of obligations of other persons; •issue redeemable stock and preferred stock; •pay dividends or distributions or redeem or repurchase capital stock; •prepay, redeem or repurchase certain debt; •make loans and investments; •create or incur liens; •restrict distributions from our subsidiaries; •sell assets and capital stock of our subsidiaries; •consolidate or merge with or into another entity, or sell all or substantially all of our assets; and •enter into new lines of business. A breach of the covenants under the indentures governing the Senior Notes or under the revolving credit facility could result in an event of defaultunder the applicable indebtedness. An event of default may allow the creditors to accelerate the related debt and may result in an acceleration of anyother debt to which a cross-acceleration or cross-default provision applies. In addition, an event of default under our credit facility would permit thelenders under the facility to terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under ourrevolving credit facility could proceed against the collateral granted to them to secure that debt. In addition, our revolving credit facility requires us to maintain certain financial ratios, including a leverage ratio. All of these restrictive covenantsmay restrict our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our revolving credit facilitymay be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of thesecovenants could result in a default under our revolving credit facility, in which case, depending on the actions taken by the lenders thereunder or theirsuccessors or assignees, such lenders could elect to declare all amounts borrowed under our revolving credit facility, together with accrued interest, tobe due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness underour revolving credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.We are subject to risks in connection with acquisitions, including the Eagle Acquisition and the Anadarko Basin Acquisition, and the integrationof significant acquisitions may be difficult. We have previously acquired reserves, properties, prospects and leaseholds from third parties, including the Eagle Acquisition and the AnadarkoBasin Acquisition. In addition, we will continue to evaluate other acquisitions of reserves, properties, prospects and leaseholds and other strategictransactions that appear to fit within our overall business strategy. The successful acquisition of assets and other producing properties requires anassessment of several factors, including:•recoverable reserves;41Table of Contents•future oil and natural gas prices and their appropriate differentials; •development and operating costs; •potential for future drilling and production; •validity of the sellers' 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 thatwe believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to becomesufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed onevery well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, thesellers may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractualindemnification for environmental liabilities and acquire properties on an "as is" basis. 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 cultureswith those of 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 andunknown liabilities; and •the challenge of attracting and retaining personnel associated with acquired operations. The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our seniormanagement may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manageour business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interruptedas a result of the integration process, our business could suffer. In addition, even if we successfully integrate operations acquired in acquisitions, we may not be possible to realize the full benefits we may expectin estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize thesebenefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity pricesin oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, failure toretain key personnel, an increase in operating or other costs or other difficulties. We may experience additional challenges integrating the assets ofprivately operated companies. If we fail to realize the benefits we anticipate from an acquisition, our results of operations and stock price may beadversely affected.42Table of ContentsOur pending sale of 3,907 gross (3,757 net) acres in the Pine Prairie field area of Evangeline Parish, Louisiana is contingent upon thesatisfaction of certain conditions and may not be consummated on the terms or timeline contemplated and may not achieve the intended results. On March 5, 2014, we executed a PSA to sell all of our ownership interest in developed and undeveloped acreage in the Pine Prairie field area ofEvangeline Parish, Louisiana to a private buyer for a purchase price of $170 million in cash, subject to standard post-closing adjustments. We expectthis transaction to close on May 1, 2014. However, the parties' obligations to consummate this transaction are conditioned upon the satisfaction orwaiver of certain closing conditions, including governmental and third party approvals. If these conditions are not satisfied or waived, the acquisitionwill not be consummated and we may be required to obtain funding for our future capital spending plans under the Bridge Facility or other sources.Furthermore, even if the transaction does close, we may not realize the anticipated benefits of the transaction fully or at all and may have to seek othersources of funding in order to fund our capital spending plans. Please see "Management's Discussion and Analysis of Financial Condition and Resultsof Operations—Liquidity and Capital Resources" for a more information on the PSA and the Bridge Facility.The inability of our significant customers to meet their obligations to us may adversely affect our financial results. We are subject to credit risk due to concentration of our oil, NGL and natural gas receivables with several significant customers. The largestpurchaser of our oil, NGL and natural gas during the year ended December 31, 2013 was ConocoPhillips, accounting for 28%, and for the year endedDecember 31, 2012 the largest purchaser of was Chevron, accounting for 41% of our total revenues for these periods. We generally do not require ourcustomers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation mayadversely affect our financial condition and results of operations.Our derivative activities could result in financial losses or could reduce our earnings. To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil, we enter into derivative instrumentsfor a portion of our oil, NGL and natural gas production. See "Management's Discussion and Analysis of Financial Condition and Results ofOperations—Quantitative and Qualitative Disclosures About Market Risk" and Note 4 to our Consolidated Financial Statements for a summary of ouroil commodity derivative positions. We did not designate any of our derivative instruments as hedges for accounting purposes, and we record allderivative instruments in our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in current earnings.Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments. Derivative instruments 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 counter-party to the derivative instrument defaults on its contractual obligations; or •there is an increase in the differential between the underlying price in the derivative instrument and actual prices received for basisdifferentials. In addition, our derivative arrangements limit the benefit we would receive from increases in the prices for oil, natural gas liquids and natural gas.43Table of ContentsLarge competitors may be attracted to our core operating areas, which may increase our costs. Our operations in the Mississippian Lime formation in northwestern Oklahoma, the Anadarko Basin in Texas and Oklahoma and the Upper GulfCoast tertiary trend in Louisiana may attract companies that have greater resources than we do. These companies may be able to pay more for productiveoil and natural gas properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than ourfinancial or human resources permit. Their presence in our areas of operations may also restrict our access to, or increase the cost of, oil and natural gasinfrastructure, drilling rigs, equipment, supplies, personnel and oilfield services, including fracking equipment and crews. In addition, these companiesmay have a greater ability to continue exploration activities during periods of low oil and natural gas prices. Our larger competitors may be able toabsorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect ourcompetitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate andselect suitable properties and to consummate transactions in a highly competitive environment. See "Business—Competition" for additional discussionof the competitive environment in which we operate.The loss of senior management or technical personnel could adversely affect our operations. We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technicalpersonnel, including our Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain,any insurance against the loss of any of these individuals.Title to the properties in which we have an interest may be impaired by title defects. We do not obtain title insurance and have not necessarily obtained drilling title opinions on all of our oil and natural gas properties. The existenceof title deficiencies with respect to our oil and natural gas properties could reduce the value or render such properties worthless, which could have amaterial adverse effect on our business and financial results. A significant portion of our acreage is undeveloped leasehold acreage, which has a greaterrisk of title defects than developed acreage. Frequently, as a result of title examinations, certain curative work may be required to correct identified titledefects, and such curative work entails time and expense. Our inability or failure to cure title defects could render some locations undrillable or cause usto lose our rights to some or all production from some of our oil and natural gas properties, which could have a material adverse effect on our businessand financial results if a comparable additional location to drill a development well cannot be identified.The proposed U.S. federal budget for fiscal year 2014 and proposed legislation contain certain provisions that, if passed as originally submitted,will have an adverse effect on our financial position, results of operations and cash flows. The Obama administration's budget proposals for fiscal year 2014 contains numerous proposed tax changes, and from time to time, legislation hasbeen introduced that would enact many of these proposed changes. The proposed budget and legislation would repeal many tax incentives anddeductions that are currently used by U.S. oil and gas companies and impose new fees. Among others, the provisions include: elimination of the abilityto fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domesticmanufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; andimplementation of a fee on non-producing federal oil and gas leases. Should some or all of these provisions become law our taxes could increase,potentially significantly, after net operating losses are exhausted, which would have a44Table of Contentsnegative impact on our net income and cash flows and could reduce our drilling activities. We do not know the ultimate impact these proposed changesmay have on our business.We are subject to various governmental regulations that may cause us to incur substantial costs. From time to time, in varying degrees, political developments and federal and state laws and regulations affect our operations. In particular, pricecontrols, taxes and other laws relating to the oil and natural gas industry, changes in these laws and changes in administrative regulations have affected,and in the future could affect, oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existinglaws and regulations or the effect of these adoptions and interpretations may have on our business or financial condition. Our business is subject to laws and regulations promulgated by federal, state and local authorities relating to the exploration for, and thedevelopment, production and marketing of, oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject tointerpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be requiredto make significant expenditures to comply with governmental laws and regulations. The discharge of oil, natural gas or other pollutants into the air, soilor water may give rise to significant liabilities on our part to the government, and third parties and may require us to incur substantial costs ofremediation.Our sales of oil and gas may expose us to extensive regulation. The FERC, the Commodity Futures Trading Commission and the Federal Trade Commission hold statutory authority to monitor certain segmentsof the physical energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud andmanipulation of such markets. With regard to our physical sales, if any, of oil and gas, we are required to observe the market-related regulationsenforced by these agencies.Our operations are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities. Our oil and natural gas exploration, production and development operations are subject to stringent and complex federal, regional, state and locallaws and regulations governing the release or disposal of materials into the environment or otherwise relating to environmental protection. These lawsand regulations may, among other things, require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration ofsubstances that can be released into the environment in connection with drilling, completion and production activities, limit or prohibit construction ordrilling activities on certain lands lying within wilderness, wetlands, and other protected areas, and impose substantial liabilities for pollution resultingfrom our operations. We may be required to make significant capital and operating expenditures to prevent releases, manage wastewater discharges andcontrol air emissions or perform remedial or other corrective actions at our wells and properties to comply with the requirements of these environmentallaws and regulations or the terms or conditions of permits issued pursuant to such requirements. Failure to comply with these laws and regulations mayresult in the assessment of administrative, civil and criminal penalties, loss of our leases, incurrence of investigatory or remedial obligations and theissuance of orders limiting or prohibiting some or all of our operations. There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling ofpetroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations,and because of historical operations and waste disposal practices at our leased and owned properties. Spills or other releases of regulated substances,including such spills and releases that occur in the future, could45Table of Contentsexpose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws andregulations, we could be subject to strict, joint and several liability for the removal or remediation of previously released materials or propertycontamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in theindustry at the time they were conducted. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction,completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could requireus to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general inaddition to our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs frominsurance.Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demandfor the oil and natural gas we produce. In December 2009, the U.S. Environmental Protection Agency, or EPA, determined that emissions of carbon dioxide, methane and othergreenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are contributing towarming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations torestrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one regulation that requires a reduction in emissions ofGHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources, effective January 2, 2011. The EPAhas also adopted rules requiring the monitoring and reporting of GHGs from certain sources in the United States, including, among others, certainonshore and offshore oil and natural gas production facilities. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of thestates have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/orregional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incurincreased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with newregulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reducedemand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverseeffect on our business, financial condition and results of operations. 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, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financialcondition and results of operations.Federal and state legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities couldresult in increased costs, additional operating restrictions or delays, which could 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 formation to fracture the surrounding rock andstimulate production. We routinely utilize hydraulic fracturing techniques in many of our oil and natural gas drilling and completion programs. Theprocess is typically regulated by state oil and natural gas commissions. However, the EPA has exercised federal regulatory authority over certainhydraulic46Table of Contentsfracturing activities involving diesel under the federal Safe Drinking Water Act, or SDWA, and recently released draft permitting guidance for hydraulicfracturing activities using diesel. In addition, in November 2011, the EPA announced plans to propose rules under the Toxic Substances Control Actrelating to the disclosure of chemical substances and mixtures used in hydraulic fracturing; however, to date, the agency has not yet taken action to doso. On August 16, 2012, the EPA published final regulations under the Clean Air Act that require additional emissions controls for the oil and naturalgas industry, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and aseparate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production activities. The finalregulations require, among other things, the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or"green completions" on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring atsuch well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices,such as flares, in lieu of performing green completions. These regulations also establish specific new requirements, effective in 2012, regardingemissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements could increase our costs ofdevelopment and production, which costs may be significant. In addition, there are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulicfracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturingpractices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore,a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. Forexample, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initialresults expected to be available by late 2012 and final results by 2014. Moreover, the EPA announced on October 20, 2011 that it is launching a studyof wastewater resulting from hydraulic fracturing activities and currently plans to propose pretreatment regulations by 2014. In addition, the U.S.Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling usinghydraulic fracturing completion methods. Certain members of the Congress have also called upon the U.S. Government Accountability Office toinvestigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleadingof investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S.Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves fromshale formations, as well as uncertainties associated with those estimates. These on-going or proposed studies could spur initiatives to further regulatehydraulic fracturing under the SDWA or otherwise. From time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of thechemicals used in the fracturing process. Moreover, some states have adopted, and other states are considering adopting, regulations that could imposemore stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations under certain circumstances. For instance,on October 20, 2011, Louisiana adopted new regulations that require hydraulic fracturing operators to publicly disclose the volume of hydraulicfracturing fluid, the type, trade name, supplier and volume of additives, and a list of chemical compounds contained in the additive, along with itsmaximum concentration, subject to certain trade secret protections. However, even trade secret chemicals will have to be identified by their chemicalfamily. Similarly, on July 1, 2012, Oklahoma adopted regulations requiring operators to publicly disclose the total volume of the hydraulic fracturingbase fluid, the trade name, supplier, and general purpose of each chemical added to the fluid, and the chemical abstract service numbers of each additiveto the fluid, subject to certain trade secret protections. A mandatory disclosure of information regarding the47Table of Contentsconstituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedingsbased upon allegations that specific chemicals used in the fracturing process could adversely affect the environment. If new laws or regulations thatsignificantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulateproduction from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatoryinitiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and attendantpermitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that weare ultimately able to produce from our reserves.Our operations are dependent on our rights and ability to receive or renew the required permits and other approvals from governmentalauthorities and other third parties. Performance of our operations require that we obtain and maintain numerous environmental and land use permits and other approvals authorizingour regulated activities. A decision by a governmental authority or other third party to deny, delay or restrictively condition the issuance of a new orrenewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on ourability to initiate or continue operations at the affected location or facility. Expansion of our existing operations is also predicated on securing thenecessary environmental or land use permits and other approvals, which we may not receive in a timely manner or at all.The enactment of derivatives legislation could impede our ability to manage business and financial risks by restricting our use of derivativeinstruments as hedges against fluctuating commodity prices. 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, includingus, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulationsimplementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is notpossible at this time to predict when this will be accomplished. In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and forswaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia inSeptember 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalentswaps contracts for, or linked to, certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new positionlimit rules are not yet final, the impact of those provisions on us is uncertain at this time. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and exchange trading. To the extent weengage in such transactions or transactions that become subject to such rules in the future, we will be required to comply or to take steps to qualify foran exemption to such requirements. Although we expect to qualify for the end-user exception to the mandatory clearing requirements for swaps enteredto hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swapdealers, may change the cost and availability of the swaps that we uses for hedging. In addition, the Act requires that regulators establish margin rulesfor uncleared swaps. Rules that require end-users to post initial or variation margin could impact liquidity and reduce cash available to us for capitalexpenditures, therefore reducing its ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules for uncleared swaps arenot yet final and their impact on us is not yet clear.48Table of Contents The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separateentity, which may not be as creditworthy as the current counterparty. Additionally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed tospeculative 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 and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect onus, our financial condition, and our results of operations. The full impact of the Dodd-Frank Act and related regulatory requirements upon the our business will not be known until the regulations areimplemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost ofderivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adverselyaffect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter,reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduceour 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 beless predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a materialadverse effect on our financial condition and results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extentwe transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is notclear.Risks Relating to our Common StockBecause we are a relatively small company, the requirements of being a public company, including compliance with the reporting requirements ofthe Exchange Act and the requirements of the Sarbanes-Oxley Act of 2002, may strain our resources, increase our costs and divert managementattention, and we may be unable to comply with these requirements in a timely or cost-effective manner. As a public company with listed debt and equity securities, we need to comply with new laws, regulations and requirements, certain corporategovernance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC, including compliance with the reporting requirements of theSecurities Exchange Act of 1934, as amended (the "Exchange Act"), and the requirements of the New York Stock Exchange, or the NYSE, with whichwe were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount oftime of our board of directors and management and will significantly increase our costs and expenses. We are required to:•institute a more comprehensive compliance function; •design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements ofSection 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company AccountingOversight Board; •comply with rules promulgated by the NYSE; •prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;49Table of Contents•establish new internal policies, such as those relating to disclosure controls and procedures and insider trading; •involve and retain to a greater degree outside counsel and accountants in the above activities; and •establish an investor relations function. In addition, being a public company subject to these rules and regulations could require us, in the future, to accept less director and officer liabilityinsurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract new oradditional qualified members to our board of directors, particularly to serve on our audit committee and compensation committee, and qualified executiveofficers.We have identified a material weakness in our internal control over financial reporting. This material weakness, if not corrected, could affect thereliability of our financial statements and have other adverse consequences. Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to furnish a report by our management on internal control over financialreporting. This report must contain, among other matters, an assessment of the effectiveness of our internal control over financial reporting, including astatement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any materialweaknesses in our internal control over financial reporting identified by our management. In addition, the report must contain a statement that ourauditors have issued an attestation report on management's assessment of such internal control over financial reporting. We have identified a material weakness in our internal control over financial reporting as of December 31, 2013, as disclosed in "Item 9A.Controls and Procedures". Failure to have effective internal controls could lead to a misstatement of our financial statements or prevent us from filingour financial statements in a timely manner. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial statements, ourbusiness decision processes may be adversely affected, our business and operating results could be harmed, investors could lose confidence in ourreported financial information, the price of our common shares could decrease and our ability to obtain additional financing, or additional financing onfavorable terms, could be adversely affected. In addition, failure to maintain effective internal control over financial reporting could result ininvestigations or sanctions by regulatory authorities. We intend to take further action to remediate the material weakness and improve the effectiveness of our internal control over financial reporting.However, we can give no assurances that the measures we may take will remediate the material weakness identified or that any additional materialweaknesses will not arise in the future due to our failure to implement and maintain adequate internal control over financial reporting. In addition, even ifwe are successful in strengthening our controls and procedures, those controls and procedures may not be adequate to prevent or identify irregularitiesor ensure the fair presentation of our financial statements included in our periodic reports filed with the SEC.We do not intend to pay, and we are currently prohibited from paying, dividends on our common stock and, consequently, your only opportunityto achieve a return on your investment is if the price of our common stock appreciates. We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently prohibited frommaking any cash dividends pursuant to the terms of our revolving credit facility and the indentures governing our Senior Notes. Consequently, youronly50Table of Contentsopportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it.We are currently controlled by First Reserve, and First Reserve and Riverstone collectively hold a majority of the voting power of our commonstock and certain actions by us will require the consent of First Reserve or Riverstone. Their interests as equity holders may conflict with theinterests of our other shareholders or our noteholders. First Reserve currently owns an economic interest in us through FR Midstates Interholding LP ("FRMI"), which owns approximately 41% of ourshares of common stock and is controlled by First Reserve. Eagle Energy, which is controlled by Riverstone Holdings, LLC ("Riverstone"), holdsSeries A Preferred Stock issued as consideration in the Eagle Property Acquisition. On a pro forma basis following conversion of the Series APreferred Stock at a conversion price of $13.50, FRMI and Riverstone (together with Eagle Energy management) will own 30% and 27% of our sharesof common stock, respectively. While they hold these interests, these entities will have significant influence over our operations, will have representatives on our board of directorsand have significant influence over all matters that require approval by our stockholders, including the approval of significant corporate transactions.This concentration of ownership will limit the ability of our stockholders to influence corporate matters, and as a result, actions may be taken that ourshareholders may not view as beneficial. In addition, we, FRMI and certain of our other stockholders have entered into a stockholders' agreement that permits FRMI to designate certain ofour director nominees and prohibits us from engaging in certain transactions without the written consent of FRMI. The stockholders' agreement provides that the following actions by us require the consent of FRMI:•incurrence of debt that would result in a total net indebtedness to EBITDA ratio in excess of 2.50:1; •authorization, creation or issuance of any equity securities (other than pursuant to compensation plans approved by the compensationcommittee or in connection with certain permitted acquisitions); •redemption, acquisition or other purchase of any of our securities (other than certain repurchases from employees and directors); •amendment, repeal or alteration of our amended and restated certificate of incorporation or amended and restated bylaws; •any acquisition or disposition (where the amount of consideration exceeds $100 million in a single transaction or $200 million in anyseries of transactions during a calendar year); •consummation of a "change in control" transaction; •adoption, approval or issuance of any "poison pill" or similar rights plan; and •entry into any plan of liquidation, dissolution or winding-up. These actions by us require the consent of FRMI until the earlier of (i) receipt by our board of directors of FRMI's written election to waive itsrights, (ii) the date FRMI ceases to hold at least 35% of our outstanding common stock, (iii) the third anniversary of the closing of our initial publicoffering or (iv) the date on which there are no directors nominated by FRMI serving as members of our board of directors.51Table of Contents The terms of the Series A Preferred Stock permit Riverstone to designate one of our director nominees, who must be an employee of Riverstone orone of its affiliates, and prohibit us from engaging in certain transactions without the consent of Riverstone, including the following actions:•the creation or issuance of any class of capital stock senior to or on parity with the Series A Preferred Stock; •the redemption, acquisition or purchase by us of any of our equity securities, other than a repurchase from an employee or director inconnection with such person's termination or as provided in the agreement pursuant to which such equity securities were issued; •any change to our certificate of incorporation or bylaws that adversely affects the rights, preferences, privileges or voting rights of theholders of the Series A Preferred Stock; •acquisitions or dispositions for which the amount of consideration exceeds 20% of our market capitalization in any single transaction or40% of our market capitalization for any series of transactions during a calendar year; •entering into certain transactions with affiliates, other than transactions that do not exceed, in the aggregate, $10 million in any calendaryear; •certain corporate transactions unless the holders of the Series A Preferred Stock would receive consideration consisting solely of cashand/or marketable securities with an aggregate fair market value equal to or greater than the liquidation preference on such shares ofSeries A Preferred Stock; and •any increase or decrease in the size of our board of directors. As a result of FRMI's and Riverstone's equity ownership or voting power, director nominees and consent rights, our ability to engage in financingtransactions or other significant transactions, such as a merger, acquisition, disposition or liquidation, may be limited. In connection with suchtransactions, conflicts of interest could arise between us and FRMI or Riverstone, and any conflict of interest may be resolved in a manner that does notfavor us.Our amended and restated certificate of incorporation contains a provision renouncing our interest and expectancy in certain corporateopportunities, which could adversely affect our business or prospects. Conflicts of interest could arise in the future between us, on the one hand, and First Reserve and its affiliates, including its portfolio companies, onthe other hand, concerning among other things, potential competitive business activities or business opportunities. First Reserve is a private equity firmin the business of making investments in entities primarily in the global energy sector. As a result, First Reserve's existing and future portfoliocompanies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor. Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest orexpectancy in, or in being offered an opportunity to participate in, any business opportunity that may be from time to time presented to First Reserve orits affiliates or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us and oursubsidiaries) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonablyhave pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of anyfiduciary or other duty, as a director or officer or controlling stockholder or otherwise, by reason of the fact that such person pursues or acquires anysuch business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or informationregarding any such business opportunity, to us unless, in the case52Table of Contentsof any such person who is our director or officer, any such business opportunity is expressly offered to such director or officer solely in his or hercapacity as our director or officer. As a result, First Reserve or its affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities,and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have theability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing ourinterest and expectancy in any business opportunity that may be from time to time presented to First Reserve and its affiliates could adversely impact ourbusiness or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours.We are a "controlled company" within the meaning of the NYSE rules and, as a result, qualify for exemptions from certain corporate governancerequirements. Upon completion of our initial public offering and the Eagle Property Acquisition, Riverstone, First Reserve and certain of our stockholders,including the Stephen P. McDaniel (a member of our Board of Directors) and members of our executive management team, control a majority of thecombined voting power of all classes of our outstanding voting stock and we are a "controlled company" within the meaning of the NYSE corporategovernance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of personsacting together is a "controlled company" and may elect not to comply with certain NYSE corporate governance requirements, including therequirements that:•a majority of the board of directors consist of independent directors; •the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the •committee's purpose and responsibilities; •the compensation committee be composed entirely of independent directors with a written charter addressing the committee's purposeand responsibilities; and •there be an annual performance evaluation of the nominating and corporate governance and compensation committees. These requirements will not apply to us as long as we remain a "controlled company." We may utilize some or all of these exemptions.ITEM 1B. UNRESOLVED STAFF COMMENTS As of December 31, 2013, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.ITEM 2. PROPERTIES Information regarding our properties is included in "Item 1. Business" above.ITEM 3. LEGAL PROCEEDINGS The information set forth under "Litigation" in Note 14—Commitments and Contingencies in the Notes to Consolidated Financial Statements setforth in Part IV, Item 15 of this Form 10-K is incorporated herein by reference.ITEM 4. MINE SAFETY DISCLOSURES None.53Table of ContentsPART II. ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUERPURCHASES OF EQUITY SECURITIES Market for Registrant's Common Equity. Our common stock is listed on the New York Stock Exchange under the symbol "MPO." The following table sets forth the range of high and low sales prices of our common stock as reported by the NYSE:Holders. The number of shareholders of record of our common stock was approximately 39 on March 18, 2014.Dividends. We have not paid any cash dividends since inception. In addition, our reserve-based revolving credit facility and the indenture governing ourSenior Notes limit and restrict our ability to pay dividends on our capital stock. We currently intend to retain all future earnings for the development andgrowth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.Stock Performance Graph. The following performance graph and related information shall not be deemed "soliciting material" or is not to be filed with the SEC, suchinformation shall not be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that wespecifically request that such information be treated as "soliciting material" or specifically incorporate such information by reference into such a filing. The performance graph below shows the cumulative total return to our commons stock holders from the date our common stock began trading onthe NYSE through December 31, 2013, as compared to the cumulative five-year total returns on the Standard and Poor's 500 Index ("S&P 500") andthe Standard and Poor's 500 Oil & Gas Exploration & Production Index ("S&P O&G E&P") for the same period of time. The comparison wasprepared on the following assumptions:•$100 was invested in our common stock at its initial public offering price of $13 per share and invested in the S&P 500 and the S&PO&G E&P on April 20, 2012 at the closing price on such date; and54 Price Range High Low 2013 First Quarter $8.95 $6.80 Second Quarter $8.58 $5.31 Third Quarter $6.55 $4.26 Fourth Quarter $6.73 $4.79 2014 First Quarter(1) $6.75 $4.13 (1)First quarter 2014 high and low ranges are calculated through March 18, 2014.Table of Contents•Dividends, if any, are reinvested. ITEM 6. SELECTED FINANCIAL DATA The following table sets forth selected financial data of the Company and its consolidated subsidiary over the five-year period ended December 31,2013, which information has been derived from the Company's audited financial statements. This information should be read in conjunction with, and isqualified in its entirety by, the more detailed information in the Company's financial statements set forth in Part IV, Item 15 of this Form 10-K. Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial data for the years endedDecember 31, 2013, 2012 and 2011 and the balance sheet data as of December 31, 2013 and 2012 are derived from our audited consolidated financialstatements and the notes thereto included elsewhere in this Annual Report on Form 10-K. The historical financial data for the year ended December 31,2009 and the balance sheet data as of December 31, 2010 and55Table of Contents2009 are derived from our audited financial statements not included in this Annual Report on Form 10-K.56 As of and for the Year Ended December 31, 2013(1) 2012(2) 2011 2010 2009 (in thousands, except per share amounts) Income Statement Data Total revenues $469,506 $247,673 $209,433 $63,052 $24,254 Net income (loss) (343,985) (150,097) 16,657 (15,635) (11,752)Net income (loss) attributable tocommon shareholders(3) (359,574) (156,597) 16,657 (15,635) (11,752)Net income (loss) per share attributableto common shareholders(4) Basic and diluted $(5.47)$(2.61) N/A N/A N/A Balance Sheet Data Total assets $2,342,107 $1,684,010 $624,656 $427,004 $284,034 Long-term debt 1,701,150 694,000 234,800 89,600 29,800 Stockholders'/members' equity 339,999 677,469 285,502 255,879 235,334 Weighted average number of commonshares outstanding 65,766 59,979 N/A N/A N/A (1)The year ended December 31, 2013 reflects the Anadarko Basin Acquisition, which closed on May 31, 2013. For a discussion ofsignificant acquisitions, see Note 6—Acquisition of Oil and Gas Properties in the Notes to the Consolidated Financial Statementsset forth in Part IV, Item 15 of this Form 10-K. (2)The year ended December 31, 2012 reflects the Eagle Property Acquisition, which closed on October 1, 2012. For a discussionof significant acquisitions, see Note 6—Acquisition of Oil and Gas Properties in the Notes to the Consolidated FinancialStatements set forth in Part IV, Item 15 of this Form 10-K. (3)The years ended December 31, 2013 and 2012 includes the effect of an undeclared Series A Preferred Stock dividend of$15.6 million and $6.5 million, which is, at the Company's option, to be paid in cash or in shares upon conversion. See Note 10—Equity and Share Based Compensation in the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 ofthis Form 10-K. (4)The net loss per share attributable to common shareholders for the year ended December 31, 2012 is on a pro forma basis, as ourcommon stock did not trade for the entirety of 2012 (trading began on the New York Stock Exchange on April 20, 2012).Table of ContentsNon-GAAP Financial Measures and Reconciliations Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financialstatements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as earnings before interest income and expense, income taxes, depreciation, depletion and amortization, propertyimpairments, asset retirement obligation accretion, unrealized derivative gains and losses and non-cash share-based compensation expense. AdjustedEBITDA is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP. We believethat Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operationsfrom period to period without regard to our financing methods or capital structure. We exclude items such as property impairments, asset retirementobligation accretion, unrealized derivative gains and losses and non-cash share-based compensation expense from net income in arriving at AdjustedEBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and bookvalues of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to,or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operatingperformance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company'sfinancial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which arecomponents of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of othercompanies. We believe that57 As of and for the Year Ended December 31, 2013(1) 2012(2) 2011 2010 2009 (in thousands) Balance Sheet Data Cash and cash equivalents $33,163 $18,878 $7,344 $11,917 $4,353 Net property and equipment 2,094,894 1,567,408 574,079 397,126 271,726 Total assets 2,342,107 1,684,010 624,656 427,004 284,034 Long-term debt 1,701,150 694,000 234,800 89,600 29,800 Stockholders'/members'equity 339,999 677,469 285,502 255,879 235,334 Other Financial Data Net cash provided byoperating activities $227,102 $137,249 $141,550 $50,768 $10,595 Net cash used in investingactivities (1,193,846) (773,608) (242,619) (139,618) (75,215)Net cash provided byfinancing activities 981,029 647,893 96,496 96,414 65,759 Adjusted EBITDA(3) 330,144 144,619 152,616 53,274 12,539 (1)The year ended December 31, 2013 reflects the Anadarko Basin Acquisition. For a discussion of significant acquisitions, seeNote 6—Acquisition of Oil and Gas Properties in the Notes to the Consolidated Financial Statements set forth in Part IV,Item 15 of this Form 10-K. (2)The year ended December 31, 2012 reflects the Eagle Property Acquisition. For a discussion of significant acquisitions, seeNote 6—Acquisition of Oil and Gas Properties in the Notes to the Consolidated Financial Statements set forth in Part IV,Item 15 of this Form 10-K. (3)Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of AdjustedEBITDA to our net income (loss) and net cash provided by operating activities, see "Non-GAAP Financial Measures andReconciliations" below.Table of ContentsAdjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debtservice requirements. The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP measure of net income (loss)and net cash provided by operating activities, respectively. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidatedfinancial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains "forward-lookingstatements" that are based on management's current expectations, estimates and projections about our business and operations, and involves risksand uncertainties. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as aresult of a number of factors, including those we discuss under "Risk Factors," "Cautionary Note Regarding Forward-Looking Statements" andelsewhere in this Annual Report on Form 10-K.58 As of and for the Year Ended December 31, 2013 2012 2011 2010 2009 (in thousands) Adjusted EBITDA reconciliation tonet income (loss): Net income (loss) $(343,985)$(150,097)$16,657 $(15,635)$(11,752)Depreciation, depletion and amortization 250,396 125,561 91,699 41,827 12,363 Impairment in carrying value of oil andgas properties 453,310 — — — 4,297 Losses on commodity derivative contracts—net 44,284 11,158 4,844 26,268 5,987 Net cash (paid) received for commodityderivative contracts not designated ashedging instruments (17,585) (15,825) (16,733) (870) 1,296 Income taxes (146,529) 157,886 — — — Interest income (33) (245) (23) (9) (6)Interest expense, net of amountscapitalized 83,138 12,999 2,094 — — Asset retirement obligation accretion 1,435 723 334 175 120 Share-based compensation 5,713 2,459 53,744 1,518 234 Adjusted EBITDA $330,144 $144,619 $152,616 $53,274 $12,539 As of and for the Year Ended December 31, 2013 2012 2011 2010 2009 (in thousands) Adjusted EBITDA reconciliation to net cashprovided by operating activities: Net cash provided by operating activities $227,102 $137,249 $141,550 $50,768 $10,595 Changes in working capital 25,892 (3,854) 9,845 2,829 1,950 Interest income (33) (245) (23) (9) (6)Interest expense, net of amounts capitalized 83,138 12,999 2,094 — — Amortization of deferred financing costs (5,955) (1,530) (850) (314) — Adjusted EBITDA $330,144 $144,619 $152,616 $53,274 $12,539 Table of Contents We are an independent exploration and production company focused on the application of modern drilling and completion techniques to oil-proneresources. Prior to October 1, 2012, all of our growth had been driven through the development of our leasehold acreage located in Louisiana. We initiatedoperations in 1993 in our North Cowards Gully project area and slowly aggregated leasehold acreage in that project area and others over the nexteighteen years. In August 2008, First Reserve acquired a majority interest in us and, along with members of our senior management, provided asignificant amount of growth capital to expand our exploration and development program in Louisiana. On October 1, 2012, the Company closed on the acquisition of all of Eagle Energy Production, LLC's producing properties as well as itsdeveloped and undeveloped acreage primarily in the Mississippian Lime liquids play in Oklahoma for $325 million in cash and 325,000 shares of theSeries A Preferred Stock with an initial liquidation preference value of $1,000 per share (the "Eagle Property Acquisition"). The Company funded thecash portion of the Eagle Property Acquisition purchase price with a portion of the net proceeds from the private placement of $600 million in aggregateprincipal amount of 10.75% senior unsecured notes due 2020 (the "2020 Senior Notes"), which also closed on October 1, 2012. On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas andOklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (the "Anadarko Basin Acquisition"), beforecustomary post-closing adjustments. The Company funded the purchase price with a portion of the net proceeds from the private placement of$700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021 (the "2021 Senior Notes" and, together with the 2020 SeniorNotes, the "Senior Notes"), which also closed on May 31, 2013. Subsequent to the closing of the Eagle Property Acquisition and the Anadarko Basin Acquisition, the Company had oil and gas operations andproperties in Louisiana, Oklahoma and Texas. At December 31, 2013, the Company operated oil and natural gas properties and evaluated performancebased on one reportable segment as there were not significantly different economic or operational environments within its oil and natural gas properties. Our current activities are focused on evaluating and developing our asset base, optimizing our acreage position, and identifying potential expansionareas across all of our operating areas. As of December 31, 2013, we had spud approximately 260 gross wells (including 81 in our Mississippianoperating area since the fourth quarter of 2012 and 35 in our Anadarko operating area since the second quarter of 2013), approximately 95% of whichproduced commercially, since the third quarter of 2008. As of December 31, 2013, our properties consisted of approximately 722 gross active producing wells, 86% of which we operate, and in whichwe held an average working interest of approximately 81% across our approximate 308,200 net acre leasehold. As of December 31, 2013, our estimatednet proved reserves were 127.8 MMBoe, of which 63% was oil or NGLs and 38% was proved developed. During the three months and year endedDecember 31, 2013, our properties had aggregate average net daily production of approximately 31,090 Boe/d and 23,902 Boe/d, respectively. On March 5, 2014, we executed a PSA to sell all of our ownership interest in developed and undeveloped acreage in the Pine Prairie field area ofEvangeline Parish, Louisiana to a private buyer for a purchase price of $170 million, subject to standard post-closing adjustments. The PSA has aneffective date of November 1, 2013 and is expected to close on May 1, 2014. Acreage subject to the transaction totaled 3,907 gross (3,757 net) acres,and does not include our acreage and production in the western part of Louisiana in Beauregard Parish or other undeveloped acreage held outside thePine Prairie field. The proceeds from the sale will be used to pay down our revolving credit facility.59Table of ContentsSources of Our Revenue Oil, natural gas and natural gas liquids. Our revenues are derived from the sale of oil and natural gas production, as well as the sale of NGLsthat are extracted from our high Btu content natural gas. Our oil and gas revenues do not include the effects of derivatives, and may vary significantlyfrom period to period as a result of changes in production volumes or commodity prices. Realized and unrealized gain (loss) on commodity derivative financial contracts. We utilize commodity derivatives to reduce our exposure tofluctuations in the prices of oil, NGLs and natural gas. In addition, we utilize derivatives to help mitigate our exposure to fluctuations in Louisiana LightSweet ("LLS") oil prices, which is the index price we receive for our Gulf Coast oil production, as compared to West Texas Intermediate ("NYMEXWTI") benchmark oil prices which is the index price we receive in the Mississippian and Anadarko Basin areas. Accordingly, our income statementsreflect (i) the recognition of unrealized gains and losses associated with our open derivative contracts as commodity prices change and commodityderivatives contracts expire or new ones are entered into, and (ii) our realized gains or losses on the settlement of these commodity derivative contracts.Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to thecontract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, unrealized lossesare recognized. Conversely, if the expected future commodity prices decrease compared to the contract prices on the derivatives, unrealized gains arerecognized. Since we have elected not to apply hedge accounting to our derivatives, we reflect the unrealized and realized gains and losses in our currentincome statement periods based on the mark-to-market value at the end of each month. Cash flows associated with derivative financial instruments arereflected in cash flow from operations in our consolidated statement of cash flows. Commodity prices. Our revenues are heavily influenced by commodity prices, which are subject to wide fluctuations in response to changes insupply and demand. For a description of factors that may impact future commodity prices, please read "Risk Factors—Risks Related to the Oil andNatural Gas Industry and Our Business" beginning on page 32. The table below sets forth the prices we received per unit of volume for our oil, naturalgas, and NGLs, both including and excluding the effects of our commodity derivative contracts.60 Years Ended December 31, 2013 2012 2011 Average Sales Prices: Oil, without realized derivatives (per Bbl) $99.18 $104.35 $110.25 Oil, with realized derivatives (per Bbl) $93.41 $95.05 $99.85 Natural gas liquids, without realized derivatives (per Bbl) $36.26 $38.27 $50.98 Natural gas liquids, with realized derivatives (per Bbl) $37.09 $40.48 (a) Natural gas, without realized derivatives (per Mcf) $3.39 $2.81 $4.20 Natural gas, with realized derivatives (per Mcf) $3.58 $3.21 (a) (a)The Company did not have hedges in place on its natural gas or NGL production prior to October 1, 2012.Table of ContentsOur Expenses Lease operating and workover expenses. These are daily costs incurred to bring oil and gas out of the ground and to the market, together withthe daily costs incurred to maintain our producing properties. Such costs also include natural gas treating expenses, as well as maintenance and repairexpenses related to our oil and gas properties. Lease operating expenses include both a portion of costs that are fixed in nature, such as infrastructurecosts, as well as variable costs resulting from additional wells and production. As production increases, our average lease operating expense per barrelof oil equivalent is typically reduced because fixed costs do not increase proportionately with production. Workover expense includes major remedialoperations on a completed well to restore, maintain, or improve a well's production and is closely correlated to the levels of workover activity. Becauseworkover projects are pursued on an as needed basis and are not regularly scheduled, workover expense is not necessarily comparable from period toperiod. Gathering and transportation. These costs are incurred for the gathering and transportation of natural gas to the contractual delivery point. For2013, these costs relate to the commencement of an amended gas transportation, gathering and processing contract during the third quarter of 2013 inthe Mississippian Lime region that included a $0.36 MMBtu gathering fee. Severance and other taxes. Severance taxes are paid on produced oil and gas based on a percentage of revenues from products sold at marketprices or at fixed rates established by federal, state, or local taxing authorities. We attempt to take full advantage of all credits and exemptions in ourvarious taxing jurisdictions. In general, the severance taxes we pay correlate to the changes in oil and gas revenues. Ad valorem taxes are property taxesassessed based on the value of property and are also included in this expense category. Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and systematicallyexpense those costs on a unit of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following typesof costs: (i) all capitalized costs, other than the cost of investments in unproved properties for which proved reserves have not yet been assigned, lessaccumulated amortization; (ii) estimated future expenditures to be incurred in developing proved reserves; and (iii) estimated dismantlement andabandonment costs, net of any associated salvage value. Impairment of oil and gas properties/Ceiling test. As a public company, we apply Rule 4-10 of Regulation S-X, which requires the full-costceiling test to be performed on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs ofproved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may notexceed this "ceiling." The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production ofproved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculatedusing the average oil and natural gas sales price we received as of the first trading day of each month over the preceding twelve months (such averageprice is held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excludedfrom the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and(iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to impairment expense in the accompanying consolidatedstatements of operations. General and administrative expense. General and administrative expense consists of overhead, including payroll and benefits for our corporatestaff, non-cash charges for share-based compensation, costs of maintaining our headquarters, franchise taxes, audit and other professional fees, legal61Table of Contentscompliance, Exchange Act reporting expenses, expenses associated with Sarbanes-Oxley compliance, investor relations, director and officer liabilityinsurance costs, and director compensation. Certain of our employees hold units in Midstates Incentive Holdings LLC that entitle the holders to a portion of the proceeds to be received byFirst Reserve, our private equity sponsor, upon sales of our common stock by FRMI. Any payments with respect to these units will only occur if andwhen First Reserve achieves certain minimum return hurdles (defined as certain multiples of First Reserve's capital contributions plus investmentexpenses) on its investment through the sale of its shares of our common stock. While these proceeds will not involve any cash payment by us, we willrecognize a non-cash compensation expense, which may be material, in the period any such payment is made. See Note 10 to our audited financialstatements for the year ended December 31, 2013. Acquisition and transaction costs. The Eagle Property Acquisition and the Anadarko Basin Acquisition qualify as the acquisition of a businessunder Accounting Standards Codification Topic 805, Business Combinations ("ASC 805"). Acquisition and transaction costs are costs the Companyhas incurred as a result of these acquisitions and include finders' fees; advisory, legal, accounting, valuation and other professional and consulting fees;and acquisition related general and administrative costs. ASC 805 requires these types of acquisition related costs to be expensed as incurred and asservices are received. Interest expense. We issued $600 million and $700 million in Senior Notes on October 1, 2012 and May 31, 2013, respectively. Additionally,we finance a portion of our working capital requirements and capital expenditures with borrowings under our revolving credit facility. As a result, weincur interest expense, a portion of which is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to ournote holders and the lenders under our revolving credit facility in interest expense, as well as the amortization of the related deferred financing costs,, netof amounts capitalized to unproved properties.Results of Operations The following tables summarize our revenues, production and price data for the periods indicated:Revenues62 Years Ended December 31, 2013 2012 2011 REVENUES: Oil sales $387,226 76%$218,430 85%$177,464 83%Natural gas liquid sales 62,340 12% 23,617 9% 15,683 7%Natural gas sales 63,187 12% 16,030 6% 20,665 10% Total oil, natural gas liquids, andnatural gas sales $512,753 100%$258,077 100%$213,812 100%Realized losses on commodity derivativecontracts, net (17,585) 40% (15,825) 142% (16,733) 345%Unrealized gains (losses) on commodityderivative contracts, net (26,699) 60% 4,667 -42% 11,889 -245% Losses on commodity derivativecontracts—net $(44,284) 100%$(11,158) 100%$(4,844) Other 1,037 754 465 Total revenues $469,506 $247,673 $209,433 Table of ContentsProductionPricesOil, Natural Gas and Natural Gas Liquids Revenues.Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 Our oil sales revenues increased by $168.8 million, or 77%, to $387.2 million during the year ended December 31, 2013 as compared to$218.4 million for the year ended December 31, 2012. Oil volumes sold increased 1,811 MBbls or 87% to 3,904 MBbls for the year endedDecember 31, 2013 from 2,093 MBbls for the year ended December 31, 2012. The increase in oil volumes sold was attributable to an increase of 1,463MBbls in production volumes from our Mississippian area attributable to a full year of production from the assets (which were acquired on October 1,2012) and the results from increased drilling activity in 2013, and the addition of 817 MBbls in production volumes from our Anadarko Basin area(which was acquired on May 31, 2013), partially offset by a decrease in Gulf Coast production of 469 MBbls. Production from the Gulf Coast declineddue to lower drilling activity during the latter half of 2013 as we focused drilling capital on our newly acquired Anadarko Basin assets. Average oilsales prices, without realized derivatives, decreased by $5.17 per barrel, or 5%, to $99.18 per barrel for the year ended December 31, 2013 as comparedto $104.35 for the year ended December 31, 2012, partly due to lower oil prices during 2013 as well as lower oil prices received for our Mississippianand Anadarko Basin production, which is priced off WTI as opposed to LLS for our Gulf Coast production. Of the $387.2 million in total oil salesrevenues, $151.7 million was from Gulf Coast operations, $155.9 million was from Mississippian and $79.6 million was from Anadarko Basin.63 Years Ended December 31, 2013 Increase(Decrease) 2012 Increase(Decrease) 2011 PRODUCTION DATA: Oil (MBbls) 3,904 87% 2,093 30% 1,610 NGLs (MBbls) 1,719 179% 617 101% 308 Natural gas (MMcf) 18,657 228% 5,695 16% 4,918 Total oil equivalents (MBoe) 8,733 139% 3,659 34% 2,737 Oil (Boe/d) 10,697 87% 5,719 30% 4,410 Natural gas liquids (Boe/d) 4,711 179% 1,686 101% 843 Natural gas (Mcf/day) 51,116 228% 15,559 16% 13,475 Average daily production (Boe/d) 23,927 139% 9,999 34% 7,499 Years Ended December 31, 2013 Increase(Decrease) 2012 Increase(Decrease) 2011 Average Sales Prices: Oil, without realized derivatives (per Bbl) $99.18 -5%$104.35 -5%$110.25 Oil, with realized derivatives (per Bbl) $93.41 -2%$95.05 -5%$99.85 NGLs, without realized derivatives (per Bbl) $36.26 -5%$38.27 -25%$50.98 NGLs, with realized derivatives (per Bbl) $37.09 -8%$40.48 — (a) Natural gas, without realized derivatives (per Mcf) $3.39 21%$2.81 -33%$4.20 Natural gas, with realized derivatives (per Mcf) $3.58 11%$3.21 — (a) (a)The Company did not have hedges in place on its NGL or natural gas production prior to October 1, 2012.Table of Contents Our NGLs sales revenues increased by $38.7 million, or 164%, to $62.3 million during the year ended December 31, 2013 as compared to$23.6 million for the year ended December 31, 2012. NGLs volumes sold increased 1,102 MBbls, or 179%, to 1,719 MBbls for the year endedDecember 31, 2013 as compared to 617 MBbls for the year ended December 31, 2012. The increase in NGLs volumes sold was attributable to anincrease of 789 MBbls of production volumes from our Mississippian area and the addition of 395 MBbls of production volumes from our AnadarkoBasin area, partially offset by a decrease in Gulf Coast production of 82 MBbls. Average NGLs prices, without realized derivatives, decreased by $2.01per barrel, or 5%, to $36.26 per barrel for the year ended December 31, 2013 as compared to $38.27 per barrel for the year ended December 31, 2012.Of the $62.3 million in total NGLs revenues, $13.9 million was from Gulf Coast operations, $34.5 million was from Mississippian and $13.9 millionwas from Anadarko Basin. Our natural gas sales revenues increased by $47.2 million, or 295%, to $63.2 million during the year ended December 31, 2013 as compared to$16.0 million for the year ended December 31, 2012. Natural gas volumes sold increased 12,962 MMcf, or 228%, to 18,657 MMcf for the year endedDecember 31, 2013 as compared to 5,695 MMcf for the year ended December 31, 2012. The increase in natural gas volumes sold was attributable to anincrease of 10,946 MMcf of production volumes from our Mississippian area and the addition of 3,489 MMcf of production volumes from ourAnadarko Basin area, partially offset by a 1,473 MMcf decrease in production from our Gulf Coast area. Average natural gas prices, without realizedderivatives, increased by $0.58 per Mcf, or 21%, to $3.39 per Mcf for the year ended December 31, 2013 as compared to $2.81 per Mcf for the yearended December 31, 2012. Of the $63.2 million in total natural gas sales revenues, $9.4 million was from Gulf Coast operations, $42.6 million wasfrom Mississippian and $11.2 million was from Anadarko Basin.Year Ended December 31, 2012 as Compared to the Year Ended December 31, 2011 Our oil sales revenues increased by $40.9 million, or 23%, to $218.4 million during the year ended December 31, 2012 as compared to$177.5 million for the year ended December 31, 2011. Oil volumes sold increased 483 MBbls or 30% to 2,093 MBbls for the year ended December 31,2012 from 1,610 MBbls for the year ended December 31, 2011. The increase in oil volumes sold was attributable to a 279 MBbls increase inproduction from our Gulf Coast area, plus the addition of 204 MBbls of production volumes from our Mississippian area, beginning on October 1,2012. Average oil sales prices, without realized derivatives, decreased by $5.90 per barrel, or 5%, to $104.35 per barrel for the year endedDecember 31, 2012 as compared to $110.25 for the year ended December 31, 2011 partly due to lower oil prices during 2012, as well as lower oilprices received for our Mississippian production, which is priced off WTI as opposed to LLS for our Gulf Coast production. Of the $218.4 million intotal oil sales revenues, $201.9 million was from Gulf Coast operations and $16.5 million was from Mississippian operations. Our NGLs sales revenues increased by $7.9 million, or 50%, to $23.6 million during the year ended December 31, 2012 as compared to$15.7 million for the year ended December 31, 2011. NGLs volumes sold increased 309 MBbls, or 101%, to 617 MBbls for the year endedDecember 31, 2012 as compared to 308 MBbls for the year ended December 31, 2011. The increase in NGLs volumes sold was attributable to a 142MBbls increase in production from our Gulf Coast area, plus the addition of 167 MBbls of production volumes from our Mississippian area, beginningon October 1, 2012. Average NGLs prices, without realized derivatives, decreased by $12.71 per barrel, or 25%, to $38.27 per barrel for the year endedDecember 31, 2012 as compared to $50.98 per barrel for the year ended December 31, 2011. Of the $23.6 million in total NGLs sales revenues,$18.0 million was from Gulf Coast operations and $5.6 million was from Mississippian operations. Our natural gas sales revenues decreased by $4.7 million, or 23%, to $16.0 million during the year ended December 31, 2012 as compared to$20.7 million for the year ended December 31, 2011. Natural gas volumes sold increased 777 MMcf, or 16%, to 5,695 MMcf for the year endedDecember 31, 201264Table of Contentsas compared to 4,918 MMcf for the year ended December 31, 2011. The increase in natural gas volumes sold was attributable to a 973 MMcf decreasein production from our Gulf Coast area, offset by the addition of 1,750 MMcf of production volumes from our Mississippian area, beginning onOctober 1, 2012. Average natural gas prices, without realized derivatives, decreased by $1.39 per Mcf, or 33%, to $2.81 per Mcf for the year endedDecember 31, 2012 as compared to $4.20 per barrel for the year ended December 31, 2011. Of the $16.0 million in total natural gas sales revenues,$10.9 million was from Gulf Coast operations and $5.1 million was from Mississippian operations.Gains/Losses on Commodity Derivative Contracts—Net.Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 Our mark-to-market ("MTM") derivative positions moved from an unrealized gain of $4.7 million as of December 31, 2012 to an unrealized lossof $26.7 million for the year ending December 31, 2013. We entered into additional derivative contracts during 2013 and the MTM change resultedfrom higher average hedge volumes and unfavorable derivative contract price variances versus the forward strip price for our production onDecember 31, 2013. The NYMEX WTI closing price on December 31, 2013 was $98.42 per barrel compared to a closing price of $91.82 per barrel onDecember 31, 2012. The realized loss on derivatives for the year ended December 31, 2013 was $17.6 million compared to a realized loss of $15.8 million for the yearended December 31, 2012. See the following table (in thousands):Year Ended December 31, 2012 as Compared to the Year Ended December 31, 2011 Our MTM derivative positions moved from an unrealized gain of $11.9 million as of December 31, 2011 to an unrealized gain of $4.7 million forthe year ending December 31, 2012. The MTM change results from higher average hedge volumes and favorable derivative contract price variancesversus the forward strip price for our production on December 31, 2012. We entered into additional derivative contracts during 2012 and, with theclosing of the Eagle Property Acquisition on October 1, 2012, we assumed the related oil, natural gas liquids and natural gas hedging instrumentsassociated with those acquired properties. The NYMEX WTI closing price on December 31, 2012 was $91.82 per barrel compared to a closing price of$98.83 per barrel on December 30, 2011 (the last day of trading of 2011). The realized loss on derivatives for the year ended December 31, 2012 was $15.8 million compared to a realized loss of $16.7 million for the yearended December 31, 2011. With the closing of the Eagle Property Acquisition, we assumed hedges on natural gas and natural gas liquids. Therefore,our realized gains/losses for the year ended December 31, 2012 included realized gains/losses on these65 Year EndedDecember 31, 2013 RealizedGain (Loss) AverageSales Price (in thousands) Oil commodity derivative contracts $(22,529)$93.41 Natural gas liquids commodity derivative contracts 1,428 $37.09 Natural gas commodity derivative contracts 3,516 $3.58 Realized net losses on commodity derivative contracts $(17,585) Table of Contentscommodities in addition to oil. Prior to assuming these derivatives as part of this acquisition, we only hedged oil. See the following table (in thousands):ExpensesLease Operating and Workover.Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 Lease operating and workover expenses increased $42.9 million, or 141%, to $73.4 million for the year ended December 31, 2013 compared to$30.5 million for the year ended December 31, 2012. Lease operating expenses increased $38.8 million, or 146%, to $65.3 million for the year endedDecember 31, 2013 as compared to $26.5 million for the year ended December 31, 2012. Lease operating expenses for the year ended December 31,2013, included a full year of costs related to the assets acquired in the Eagle Property Acquisition (compared to only three months for the year endedDecember 31, 2012) and seven months of costs related to the assets acquired in the Anadarko Basin Acquisition which closed on May 31, 2013. Ofthis increase, $31.3 million relates to the increase in producing well count in all areas, which increased approximately 150% year over year due to theAnadarko Basin Acquisition and increased drilling activity in the Mississippian area. The remaining $7.5 million is attributable to surface maintenanceand other costs. During 2013, we continued to make investments in our operating areas to reduce lease operating costs, specifically in salt waterdisposal infrastructure in our Gulf Coast region and in our electrical infrastructure and salt water disposal infrastructure in the Mississippian. We expectthese investments to reduce salt water disposal and electricity costs during 2014. Workover expenses increased $4.1 million, or 103%, to $8.1 millionfor the year ended December 31, 2013, as compared to $4.0 million for the year ended December 31, 2012. Of this increase, approximately $2.9 millionrelates to the Mississippian area workover costs and Year EndedDecember 31, 2012 RealizedGain (Loss) AverageSales Price (in thousands) Oil commodity derivative contracts $(19,460)$95.05 Natural gas liquids commodity derivative contracts 1,362 $40.48 Natural gas commodity derivative contracts 2,273 $3.21 Realized net losses on commodity derivative contracts $(15,825) Year Ended December 31, Year Ended December 31, 2013 2012 2011 2013 2012 2011 (in thousands) (per Boe) EXPENSES: Lease operating andworkover $73,414 $30,500 $16,117 $8.41 $8.34 $5.89 Gathering andtransportation 5,455 — — $0.62 $— $— Severance and othertaxes 27,237 24,921 13,640 $3.12 $6.81 $4.98 Asset retirementaccretion 1,435 723 334 $0.17 $0.20 $0.12 Depreciation, depletion,and amortization 250,396 125,561 91,699 $28.67 $34.32 $33.50 Impairment in carryingvalue of oil and gasproperties 453,310 — — $51.91 $— $— General andadministrative 53,250 30,541 68,915 $6.10 $8.35 $25.18 Acquisition andtransaction costs 11,803 14,884 — $1.35 $4.07 $— Other 615 — — $0.07 $— $— Total expenses $876,915 $227,130 $190,705 $100.42 $62.09 $69.67 relates to the Mississippian area workover costs and66Table of Contents$1.3 million relates to the Anadarko area workover costs offset by a decrease of $0.1 million in Gulf Coast workover costs. Lease operating andworkover expenses increased to $8.41 per Boe for the year ended December 31, 2013 from $8.34 per Boe for the year ended December 31, 2012, anincrease of 1%, which was primarily attributable to the factors discussed above.Year Ended December 31, 2012 as Compared to the Year Ended December 31, 2011 Lease operating and workover expenses increased $14.4 million, or 89%, to $30.5 million for the year ended December 31, 2012 compared to$16.1 million for the year ended December 31, 2011. Lease operating expenses increased $12.5 million, or 89%, to $26.5 million for the year endedDecember 31, 2012 as compared to $14.0 million for the year ended December 31, 2011. This increase was due to the Eagle Property Acquisitioncompleted on October 1, 2012 and the associated lease operating costs of $2.6 million, as well as increased surface maintenance costs of $3.0 million,saltwater disposal costs of $1.3 million and an increase in costs associated with higher producing well count of $5.4 million. During the fourth quarterof 2012, we completed saltwater disposal wells in the Pine Prairie, South Bearhead Creek and West Gordon areas which we believe will reduce oursaltwater disposal costs in the future. Workover expenses increased $1.9 million, or 90%, to $4.0 million for the year ended December 31, 2012, ofwhich the Eagle Property Acquisition accounted for $1.0 million, as compared to $2.1 million for the year ended December 31, 2011. We completed 28workovers in 2012, which was an increase of four projects over the 24 workovers completed in 2011. Lease operating and workover expensesincreased to $8.34 per Boe for the year ended December 31, 2012 from $5.89 per Boe for the year ended December 31, 2011, an increase of 42%,which was primarily attributable to the factors discussed above.Gathering and TransportationYear Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 Gathering and transportation expenses were $5.5 million for the year ended December 31, 2013. These expenses are attributable to thecommencement of an amended gas transportation, gathering and processing contract during the third quarter of 2013 in the Mississippian area thatprovided for additional third party natural gas processing capacity and restructured the contract pricing provisions to include a $0.36 MMBtu gatheringfee based up on wellhead volumes.Severance and Other Taxes.Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 Severance and other taxes increased $2.3 million, or 9%, to $27.2 million for the year ended December 31, 2013 as compared to $24.9 million forthe year ended December 31, 2012. Severance taxes decreased by $0.8 million, or 4%, and accounted for $21.3 million of the 2013 amount. Thisdecrease was primarily attributable to the geographic production mix, with lower oil, NGL and natural gas sales revenue from the Gulf Coast area, andto higher oil, NGLs and natural gas sales revenue from the Mississippian and Anadarko Basin, where severance tax rates are lower than in the GulfCoast. Severance taxes for the year ended December 31, 2013 and 2012 were 4.2% and 8.6%, respectively, as a percentage of oil, NGL and natural gassales revenue.67 Year Ended December 31, 2013 2012 2011 (in thousands) Total oil, NGL, and natural gas sales $512,753 $258,077 $213,812 Severance taxes 21,338 22,121 12,421 Ad valorem 5,899 2,800 1,219 Severance and other taxes $27,237 $24,921 $13,640 Severance taxes as a percentage of sales 4.2% 8.6% 5.8%Severance and other taxes as a percentage of sales 5.3% 9.7% 6.4%Table of Contents Ad valorem taxes increased $3.1 million, or 111%, to $5.9 million for the year ended December 31, 2013 as compared to $2.8 million for the yearended December 31, 2012. This change directly correlates to the increase in active well count, which increased approximately 150% year over year dueto the Anadarko Basin Acquisition and development drilling 2013 across all areas.Year Ended December 31, 2012 as Compared to the Year Ended December 31, 2011 Severance and other taxes increased $11.3 million, or 83%, to $24.9 million for the year ended December 31, 2012 as compared to $13.6 millionfor the year ended December 31, 2011. Severance taxes increased by $9.7 million, or 78%, and accounted for $22.1 million of the 2012 amount. Thisincrease was primarily attributable to higher oil, natural gas and NGLs sales revenue during the 2012 period. Severance taxes for the year endedDecember 31, 2012 and 2011 were 8.6% and 5.8%, respectively, as a percentage of oil, natural gas and NGLs sales revenue. The severance tax rate forthe year ended December 31, 2012 was higher than the severance tax rate for the year ended December 31, 2011 due to a severance tax refund of$5.4 million in 2011 and higher oil, natural gas and NGL sales revenue during the year ended December 31, 2012. Excluding the refund, severancetaxes for the year ended December 31, 2011 would have been $17.8 million, or 8.3% as a percentage of oil, NGLs and natural gas sales revenue, ascompared to 8.6% for the year ended December 31, 2012. Ad valorem taxes increased $1.6 million, or 133%, to $2.8 million for the year ended December 31, 2012 as compared to the year endedDecember 31, 2011. This change directly correlates to the increase in active wells, which increased from 92 to 294 year over year.Depreciation, Depletion and Amortization (DD&A).Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 DD&A expense increased $124.8 million, or 99%, to $250.4 million for the year ended December 31, 2013 compared to $125.6 million for theyear ended December 31, 2012. The DD&A rate for the year ended December 31, 2013 was $28.67 per Boe compared to $34.32 per Boe for the yearended December 31, 2012. The increase in total DD&A expense for the year ended December 31, 2013 was primarily due to higher oil, NGLs andnatural gas production attributable to a full year of production from the Mississippian assets acquired in October 2012, the addition of production fromthe Anadarko Basin Acquisition and developmental drilling during 2013. The lower DD&A rate per Boe is attributable to the addition of reserves withthe Anadarko Basin Acquisition, as well as overall growth in proved reserves during 2013.Year Ended December 31, 2012 as Compared to the Year Ended December 31, 2011 DD&A expense increased $33.9 million, or 37%, to $125.6 million for the year ended December 31, 2012 compared to $91.7 million for the yearended December 31, 2011. The DD&A rate for the year ended December 31, 2012 was $34.32 per Boe compared to $33.50 per Boe for the year endedDecember 31, 2011. The increase in DD&A expense for the year ended December 31, 2012 was primarily due to higher capital expenditures related toincreased drilling and completion activities during the year, which resulted in a higher amortization base, as well as DD&A expense related to the EagleProperty Acquisition, partially offset by the impact of higher proved reserves.Impairment of Oil and Gas Properties.Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 Our impairment of oil and gas properties pursuant to the full cost "ceiling test" was $319.6 million, net of taxes, for the year ended December 31,2013. There was no impairment for the year ended December 31, 2012.68Table of Contents The most significant factors affecting the impairment related to the transfer of unevaluated property costs to the full cost pool during 2013 andnegative reserve revisions in our Gulf Coast area. During 2013, we transferred $61.2 million of Gulf Coast unevaluated property costs to the full costpool based upon our lack of future plans for further evaluation or development of those leases, and $168.4 million of Mississippian unevaluatedproperty costs attributable to leases that expired during 2013 or that we currently intend to allow to expire in 2014. The negative reserve revisions in ourGulf Coast area were mainly attributable to variability in well performance, our decision during the second quarter to halt further development in ourWest Gordon field and unfavorable cost revisions.General and Administrative (G&A).Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 Our G&A expenses increased to $53.3 million for the year ended December 31, 2013 from $30.5 million for the year ended December 31, 2012.The increase in G&A expenses of $22.8 million, or 75%, was primarily due to salary, benefits, and other expenses of $10.7 million related to theincrease in headcount, which increased from 93 full-time employees at December 31, 2012 to 217 full-time employees at December 31, 2013; anincrease in payments made under the Eagle Transition Services Agreement of $0.6 million; payments made under the Panther Transition ServicesAgreement of $10.2 million; and other costs of $1.3 million.Year Ended December 31, 2012 as Compared to the Year Ended December 31, 2011 Our G&A expenses decreased to $30.5 million for the year ended December 31, 2012 from $68.9 million for the year ended December 31, 2011.The decrease in G&A expenses of $38.4 million, or 56%, was primarily due to the expenses related to share-based compensation, which included a$53.7 million non-cash charge for share-based compensation for the year ended December 31, 2011, compared to a $2.5 million non-cash charge for theyear ended December 31, 2012. Share-based compensation expense for the year ended December 31, 2011 included expense related to the acceleratedvesting in November 2011 of restricted stock of one of our affiliates held by certain of our employees, as well as expense attributable to the change infair value of certain equity awards accounted for by the Company as liability awards up to December 5, 2011. (See "Notes to Consolidated FinancialStatements—Note 10—Member's Equity and Share-Based Compensation"). Offsetting this net decrease of $51.2 million, were additional expenses of$4.4 million related to the increase in headcount, which increased from 51 full-time employees at December 31, 2011 to 93 full-time employees atDecember 31, 2012; payments made under the Eagle Transition Services Agreement (TSA) of $1.3 million; bonus expense of $2.0 million; professionalfees of $2.9 million; and rent and technology costs of $1.1 million.Acquisition and Transaction Costs.Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 Our acquisition and transaction costs decreased by $3.1 million for the year ended December 31, 2013 from $14.9 million for the year endedDecember 31, 2012. These total costs of $11.8 million incurred in 2013 represent our expenses through December 31, 2013 related to the AnadarkoBasin Acquisition and are primarily attributable to due diligence, legal and other advisory fees that are required to be expensed under US GAAP.Year Ended December 31, 2012 as Compared to the Year Ended December 31, 2011 Our acquisition and transaction costs increased by $14.9 million for the year ended December 31, 2012 compared to no acquisition and transactioncosts for the year ended December 31, 2011. These costs represent our expenses through December 31, 2012 related to the Eagle Property Acquisitionand are primarily attributable to due diligence, legal and other advisory fees that are required to be expensed under US GAAP.69Table of ContentsOther Income (Expense)Interest Expense.Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 Interest expense (before capitalized interest) for the years ended December 31, 2013 and 2012 was $115.4 million and $24.2 million, respectively.The increase in interest expense was primarily due to the issuance during 2013 of the 2021 Senior Notes (as discussed below) and a full year of interestexpense associated with the 2020 Senior Notes (as discussed below) issued during 2012, in addition to a higher average outstanding balance under ourrevolving credit facility during the 2013 period. Our average outstanding balance under our revolving credit facility was $252.7 million during the 2013period, versus $160.0 million for the 2012 period, and related to $7.1 million of the total interest expense of $115.4 million. The remainder of theinterest expense for the year ended December 31, 2013, $108.3 million, related to interest expense of $37.8 million on the 2021 Senior Notes,$64.5 million on the 2020 Senior Notes, and amortization of deferred financing costs of $6.0 million. Of total interest expense, $32.2 million and$11.2 million was capitalized, resulting in $83.1 million and $13.0 million in net interest expense for years ended December 31, 2013 and 2012,respectively.Year Ended December 31, 2012 as Compared to the Year Ended December 31, 2011 Interest expense before capitalized interest for the years ended December 31, 2012 and 2011 was $24.2 million and $4.7 million, respectively. Theincrease in interest expense was primarily due to the issuance of the 2020 Senior Notes in October 2012 and higher average outstanding balance underour revolving credit facility during the 2012 period. Our average outstanding balance under the revolver was $160.0 million during the 2012 period,versus $147.3 million for the 2011 period, and related to $4.7 million of the total interest expense of $24.2 million. The remainder of the interestexpense for the year ended December 31, 2012, $19.5 million, related to interest expense of $16.1 million on the 2020 Senior Notes, $2.1 millionassociated with our Preferred Units which were redeemed in April 2012, and amortization of deferred financing costs of $1.3 million. Of total interestexpense, $11.2 million and $2.6 million was capitalized, resulting in $13.0 million and $2.1 million in interest expense for years ended December 31,2012 and 2011, respectively.Provision for Income Taxes.Year Ended December 31, 2013 as Compared to the Year Ended December 31, 2012 Income tax benefit was $146.5 million for the year ended December 31, 2013. This represents an application of our estimated effective tax rate(including state income taxes) for the year ended December 31, 2013 of 29.9% to the loss incurred throughout the year. The significant reasons for thechange from an income tax expense to a benefit during the year ended December 31, 2013 were the absence of a change in tax status charge during2013 (as this event took place in 2012), and the occurrence of a book loss for the year ended December 31, 2013.70 Year Ended December 31, 2013 2012 2011 OTHER INCOME (EXPENSE) Interest income $33 $245 $23 Interest expense (115,383) (24,174) (4,694)Capitalized Interest 32,245 11,175 2,600 Interest expense—net of amounts capitalized (83,138) (12,999) (2,094) Total other income (expense) $(83,105)$(12,754)$(2,071) Table of Contents In light of the impairment of oil and gas properties, we have recorded a $45.7 million valuation allowance against our federal and State ofLouisiana tax net operating losses ("NOL"), as we do not believe that it is more-likely-than-not that this portion of our NOLs are realizable. We believethat the balance of the NOLs are realizable only to the extent of future taxable income primarily related to the excess of book carrying value of propertiesover their respective tax bases. No other sources of future taxable income are considered in this judgment.Year Ended December 31, 2012 as Compared to the Year Ended December 31, 2011 Income tax expense was $157.9 million for the year ended December 31, 2012. We were not a tax paying entity during the 2011 correspondingperiod and therefore, no income tax expense was recorded. With the consummation of our reorganization in connection with our initial public offeringcompleted on April 25, 2012, we became a tax paying entity and as such, were required to record a charge against income equal to the estimated taxeffect of the excess of the book carrying value of our net assets (primarily producing oil and gas properties) over their collective estimated tax bases asof the reorganization date. As a result, during the year ended December 31, 2012, we recorded a tax charge of $149.5 million associated with thereorganization. During the year ended December 31, 2012, we also recorded $8.4 million of income tax expense related to operations. This represents anapplication of our estimated effective tax rate (including state income taxes) for the year ended December 31, 2012 of 40% to our income earned fromthe reorganization date through the period end.Liquidity and Capital Resources At December 31, 2013, our liquidity was $132 million, consisting of $99 million of available borrowing capacity under our revolving credit facilityand $33 million of cash and cash equivalents. Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. We expect to investbetween $500 million and $550 million of capital for exploration, development and lease and seismic acquisition in 2014. Additionally, we expect tocapitalize between $16 million and $22 million of interest expense. Our future success in growing proved reserves and production will be highlydependent on our ability to access additional outside sources of capital, via either the debt or equity markets, through growth in our reserve based creditfacility or by securing other external sources of funding. As part of that process, on March 5, 2014, we executed a PSA to sell all of our ownershipinterest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for a purchase price of$170 million in cash, subject to standard post-closing adjustments. The PSA has an effective date of November 1, 2013 and is expected to close onMay 1, 2014. Acreage subject to the transaction totaled 3,907 gross (3,757 net) acres, and does not include our acreage and production in the westernpart of Louisiana in Beauregard Parish or other undeveloped acreage held outside the Pine Prairie field. The proceeds from the sale will be used to paydown our revolving credit facility. Additionally, in order to provide additional capital resources during 2014, we entered into commitment letters with SunTrust Bank, SunTrustRobinson Humphrey, Inc., Morgan Stanley Senior Funding, Inc., Bank of America N.A., Goldman Sachs Bank USA, Merrill Lynch, Piece, Fenner &Smith Incorporated, Natixis New York Branch and Royal Bank of Canada on March 9, 2014 to, among other things, provide for a Senior SecuredBridge Facility ("Bridge Facility") in the amount of $125 million and to provide for a commitment ("RBL Backstop") to provide a backstop revolvercredit facility in the event that an amendment to our existing revolving credit facility to permit the consummation of the Bridge Facility and a revisedborrowing base of $475 million cannot be obtained. The Bridge Facility would be secured by a first priority lien on our Gulf Coast assets and a second lien on our Mississippian and Anadarko assets.Any obligations under the Bridge Facility would be71Table of Contentsguaranteed by the same entities that guaranty the existing credit facility. Advances under the Bridge Facility would be available through September 30,2014, would be funded in tranches of $50 million (subject to availability), initially bear interest at LIBOR plus 4.5% (subject to a 0.50% increase ininterest rate at September 30, 2014, December 31, 2014 and March 31, 2015) and mature on the first anniversary of the closing date. Interest on anyadvances is payable quarterly in cash. Upon maturity, any amounts outstanding on the Bridge Facility would be converted into a senior secured termloan or, at any time thereafter at the option of the lenders, into senior secured exchange notes maturing in September 2019. Additionally, lenders underthe Bridge Facility will have a securities demand if our total liquidity (as defined therein) falls below $50 million, provided that this provision will notapply until June 1, 2014, so long as the executed PSA discussed above remains in place. The Bridge Facility would be pre-payable in whole or in partwithout penalty or premium and would be subject to mandatory prepayment in the event of Louisiana asset sales (including the Pine Prairie transactiondiscussed above), issuance of debt or equity, occurrence of a change in control or certain other events. We have agreed to pay a 1.75% commitment fee,a 1.25% funding fee and a 2.25% fee upon the rollover. The definitive loan documentation for the Bridge Facility will include certain representationsand warranties, affirmative, negative and financial covenants and events of default customary for bridge loan financings, including limitations onincurrence of indebtedness that, prior to any rollover, will be more restrictive than those contained in our existing credit facility. In the event that an amendment accommodating the Bridge Facility, the transactions contemplated thereby and a borrowing base of $475 millioncannot be obtained under the existing credit facility, the RBL Backstop provides a commitment to provide a new credit facility on substantially the sameterms as our existing credit facility, including the notional amount of $750 million and a maturity date of May 2018, but with appropriate modificationsto (i) release our Louisiana assets from the borrowing base facility to allow for the Bridge Facility and the potential sale pursuant to the PSA, (ii) reducethe borrowing base under the existing credit facility from $500 million to $475 million, (iii) increase the leverage ratio by 0.50 for the quarter of and thetwo quarters following the sale of Pine Prairie for net proceeds greater than $100 million, (iv) allow for the Bridge Facility to be secured by a secondlien on the Mississippian and Anadarko assets, and (v) increase the applicable interest rate under the existing credit facility by 0.25%. Lendersparticipating in the RBL Backstop are to receive an underwriting fee of 0.25% whether the RBL Backstop is utilized or not. In the event the existingcredit agreement is not amended for the above terms and the RBL Backstop is utilized, participating lenders will receive an additional underwriting feeof 1.00%. Other terms of the backstop credit facility would remain materially unchanged from those contained in our existing credit facility. We expect to execute the definitive documentation of the new reserve based credit facility and the Bridge Facility during first quarter of 2014. We believe that the proceeds from the sale of Pine Prairie discussed above or, in the event we are unable to close the PSA, proceeds available to usunder our Bridge Facility, together with expected cash flow from operations and borrowings available under our amended credit facility, will besufficient to fund our capital spending plans through 2015. We plan to continue pursuing additional strategic options that would improve our financialflexibility and provide additional long-term liquidity, including the sale of our remaining Gulf Coast producing assets, other non-core asset sales andpossible joint-ventures or farm-outs on our properties. Discussions are in various states of progress with a variety of interested third parties regardingassets sales or potential joint-ventures, but we are currently unable to predict the timing of any transaction and no assurance can be given that we willreach any agreement with a potential counterparty. Though we have no current plans to do so, we may from time to time seek to retire, purchase or exchange our outstanding debt in open marketpurchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our72Table of Contentsliquidity requirements, contractual restrictions and other factors. The amounts involved may be material.Significant Sources of CapitalMandatorily Redeemable Convertible Preferred Units. In December 2011, Holdings LLC, FR Midstates Holdings LLC ("FR Midstates") and Midstates Petroleum Holdings, Inc. ("Petroleum Inc.")entered into an amended and restated limited liability company agreement, which was later amended in March 2012, to provide for the issuance of up to65,000, or $65 million in aggregate value, of certain mandatorily redeemable convertible preferred units (the "Preferred Units") between December 15,2011 and June 10, 2015. The Preferred Units had a liquidation value of $1,000 per unit and bore interest, compounded quarterly, at a rate of 8% plusthe greater of LIBOR or 1.5%. The Preferred Units were convertible into units of Holdings LLC on or after the one year anniversary of the date ofissuance into a number of common units with a fair market value (as determined by the Board) equal to the liquidation value plus any accrued interestand were redeemable for cash at any time at the option of Holdings LLC, but were mandatorily redeemable for cash on June 10, 2015, unless otherwiseconverted. In addition, a fixed interest charge of 1.5% of the aggregate capital invested in the Preferred Units was payable upon redemption orconversion. On January 4, 2012, and again on February 9, 2012, Holdings LLC issued 20,000 Preferred Units (for a total of 40,000 Preferred Units) to FRMidstates for aggregate cash proceeds of $40.0 million. On April 3, 2012, Holdings LLC issued an additional 25,000 preferred units to FR Midstatesfor aggregate cash proceeds of $25.0 million. On April 26, 2012, we used $67.1 million of the proceeds from our initial public offering to redeem the Preferred Units in full, including interestand other charges. Accordingly, there are no Preferred Units outstanding as of December 31, 2012. We recorded $2.1 million related to interest expenseassociated with these Preferred Units for the year ended December 31, 2012. We recorded no related interest expense in for the year ended December31, 2013.Reserve-based Credit Facility. As of December 31, 2013, our credit facility consisted of a $750 million senior revolving credit facility (the "Credit Facility") with a borrowingbase of $500 million, as recently redetermined on September 26, 2013, when the borrowing base was increased from $425 million. At December 31,2013, outstanding letters of credit obligations total $0.2 million. The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of our oil and natural gas properties andcurrently bear interest at LIBOR plus an applicable margin, depending upon our borrowing base utilization, between 1.75% and 2.75% per annum. AtDecember 31, 2013 and December 31, 2012, the weighted average interest rate was 2.5% and 2.5%, respectively. In addition to interest expense, the Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at therate of either 0.375% or 0.50% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings duringeach quarter. The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October and up to one additional time per sixmonth period following each scheduled borrowing base redetermination, as may be requested by us or the administrative agent, acting on behalf oflenders holding at least two-thirds of the outstanding loans and other obligations. The next scheduled borrowing base redetermination date is October 1,2014, assuming the financing discussed above in "Liquidity & Capital Resources" closes as planned.73Table of Contents Under the terms of the Credit Facility, we are required to repay the amount by which the principal balance of its outstanding loans and its letter ofcredit obligations exceed its redetermined borrowing base. We are permitted to make such repayment in six equal successive monthly paymentscommencing 30 days following the administrative agent's notice regarding such borrowing base reduction. On September 26, 2013, we entered into the Assignment and Fourth Amendment to the Second Amended and Restated Credit Agreement amongthe Company, as parent, Midstates Sub, as borrower, SunTrust Bank as administrative agent, and the other lenders and parties party thereto (the "FourthAmendment"). The Fourth Amendment amended the Credit Facility to provide that the Company's ratio of total net indebtedness to EBITDA for the trailing fourfiscal quarter period ending on the last day of such fiscal quarter cannot exceed (i) 4.75:1.0, for the fiscal quarters ending December 31, 2013 andMarch 31, 2014, (ii) 4.50:1.0, for the fiscal quarters ending June 30, 2014, (iii) 4.25:1.0, for the fiscal quarters ending September 30, 2014 andDecember 31, 2014, and (iv) 4.00:1.0, for the fiscal quarter ending March 31, 2015 and each fiscal quarter thereafter. We also agreed to pay a one-timefee of 0.50% to each lender on the portion of their commitment to the borrowing base under the Fourth Amendment in excess of their commitment priorto the Fourth Amendment, and a one-time fee of 0.10% to each lender on the lesser of such lenders commitment immediately prior to, or after givingeffect to, the Fourth Amendment. The Credit Facility contains financial covenants, in addition to the maximum ratio of debt to EBITDA discussed above, which, among other things,set a minimum current ratio (as defined therein) of not less than 1.0 to 1.0 and various other standard affirmative and negative covenants including, butnot limited to, restrictions on our ability to make any dividends, distributions or redemptions. As of December 31, 2013, we were in compliance with the minimum current ratio and the ratio of debt to EBITDA covenants as set forth in theCredit Facility. Our current ratio at December 31, 2013 was 1.3 to 1.0. At December 31, 2013, our ratio of debt to EBITDA was 4.4 to 1.0.Initial Public Offering. On April 25, 2012, we completed our initial public offering. Our net proceeds from the sale of 18,000,000 of our common shares in the initialpublic offering, after underwriting discounts and commissions, were $220.0 million (or $213.6 million after offering expenses paid directly by us). Ofthe net proceeds, $67.1 million was used to redeem the Preferred Units, including interest and other charges, and $99.0 million was used to repay aportion of our borrowings under our revolving credit facility. The remaining proceeds were retained to fund the execution of our growth strategythrough our drilling program.2020 Senior Notes. On October 1, 2012, we issued $600 million in aggregate principal amount of 10.75% senior notes due 2020 (the "2020 Outstanding Notes") in aprivate placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the "Securities Act"). OnOctober 29, 2013, substantially all of the 2020 Outstanding Notes were exchanged for an equal principal amount of registered 10.75% seniorsubordinated notes due 2020 pursuant to an effective registration statement on Form S-4 filed on August 30, 2013 under the Securities Act (the "2020Exchange Notes"). The 2020 Exchange Notes are identical to the 2020 Outstanding Notes except that the 2020 Exchange Notes are registered under theSecurities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. As used in this Form 10-K, the term"2020 Senior Notes" refers to both the 2020 Outstanding Notes and the 2020 Exchange Notes. The 2020 Senior Notes were co-issued on a joint andseveral basis with our wholly owned subsidiary, Midstates Sub.74Table of Contents At any time prior to October 1, 2015, we may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2020Senior Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the 2020 SeniorNotes, plus any accrued and unpaid interest up to the redemption date. In addition, at any time before October 1, 2016, we may redeem all or a part ofthe 2020 Senior Notes at a redemption price equal to 100% of the principal amount of 2020 Senior Notes redeemed plus the Applicable Premium (asdefined in the Indenture) at the redemption date, plus any accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, up to,the redemption date. On or after October 1, 2016, we may redeem all or a part of the 2020 Senior Notes at varying redemption prices (expressed aspercentages of principal amount) set forth in the Indenture plus accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any,on the 2020 Senior Notes redeemed, up to, the redemption date. The Indenture contains covenants that, among other things, restrict our ability to: (i) incur additional indebtedness, guarantee indebtedness or issuecertain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, orrepurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain typesof transactions with our affiliates; (vii) consolidate, merge or sell substantially all of the Company's assets; (viii) prepay, redeem or repurchase certaindebt; (ix) alter the business we conducts and (x) enter into agreements restricting the ability of our current and any future subsidiaries to pay dividends.The 2020 Senior Notes Indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the abilityof Midstates Sub to pay dividends or make loans to us or limit our ability to advance loans to Midstates Sub. Upon the occurrence of certain change of control events, as defined in the Indenture, each holder of the 2020 Senior Notes will have the right torequire that we repurchase all or a portion of such holder's 2020 Senior Notes in cash at a purchase price equal to 101% of the aggregate principalamount thereof plus any accrued and unpaid interest to the date of repurchase.2021 Senior Notes. On May 31, 2013, we issued $700 million in aggregate principal amount of 9.25% senior notes due 2021 (the "2021 Outstanding Notes") in aprivate placement conducted pursuant to Rule 144A and Regulation S under the Securities Act. On October 29, 2013, all of the 2021 Outstanding Noteswere exchanged for an equal principal amount of registered 9.25% senior subordinated notes due 2021 pursuant to an effective registration statement onForm S-4 filed on August 30, 2013 under the Securities Act (the "2021 Exchange Notes"). The 2021 Exchange Notes are identical to the 2021Outstanding Notes except that the 2021 Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registrationrights or provisions for additional interest. As used in this Form 10-K, the term "2021 Senior Notes" refers to both the 2021 Outstanding Notes and the2021 Exchange Notes. The proceeds from the offering of $700 million (net of the initial purchasers' discount and related offering expenses) were usedto fund the Anadarko Basin Acquisition and the related expenses, to pay the expenses related to an amendment to our revolving credit facility, to repay$34.3 million in outstanding borrowings under our Credit Facility, and for general corporate purposes. The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes. The 2021 Senior Notes were co-issued on a joint and several basis with Midstates Sub. On or prior to May 31, 2014, we may redeem up to $100.0 million of aggregate principal amount of the 2021 Senior Notes with the net cashproceeds from any Equity Offerings (as such term is defined in the 2021 Senior Notes Indenture) at a redemption price equal to 103% of the principalamount plus accrued and unpaid interest.75Table of Contents Prior to June 1, 2016, we may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes (lessthe amount of 2021 Senior Notes redeemed pursuant to the preceding paragraph) with the net proceeds of any Equity Offerings at a redemption price of109.25% of the principal amount of the 2021 Senior Notes redeemed, plus any accrued and unpaid interest, if any, up to the redemption date. Inaddition, at any time before June 1, 2016, we may redeem all or a part of the 2021 Senior Notes at a redemption price equal to 100% of the principalamount of the 2021 Senior Notes redeemed plus the Applicable Premium (as defined in the Indenture) at the redemption date, plus any accrued andunpaid interest and Additional Interest (as defined in the 2021 Senior Notes Indenture), if any, up to, the redemption date. On or after October 1, 2016,we may redeem all or a part of the 2021 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2021Senior Notes Indenture plus accrued and unpaid interest and Additional Interest (as defined in the 2021 Senior Notes Indenture), if any, on the 2021Senior Notes redeemed, up to, the redemption date. The terms of the covenants and change in control provisions in the 2021 Senior Notes Indenture are substantially identical to those of the 2020Senior Notes discussed above. The 2021 Senior Notes indenture does not create any restricted assets within Midstates Sub, nor does it impose anysignificant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advanceloans to Midstates Sub.Series A Preferred Stock. On October 1, 2012 we issued 325,000 shares of our Series A Preferred Stock as part of the purchase price paid to complete the Eagle PropertyAcquisition. The shares of Series A Preferred Stock have an initial liquidation value of $1,000 per share and are convertible into shares of our commonstock on or after October 1, 2013. At such time, the Series A Preferred Stock may be converted, in whole but not in part, at the option of the holders ofa majority of the outstanding shares of Series A Preferred Stock, into a number of shares of our common stock calculated by dividing the then-currentliquidation preference by the conversion price of $13.50 per share. If not previously converted, the Series A Preferred Stock will be subject tomandatory conversion into shares of our common stock on September 30, 2015 at a conversion price based upon the volume weighted average price ofour common stock during the 15 trading days immediately prior to the mandatory conversion date, but in no instance will the price be greater than$13.50 per share or less than $11.00 per share. Dividends on the Series A Preferred Stock will accrue at a rate of 8.0% per annum, payablesemiannually, at our sole option, in cash or through an increase in the liquidation preference. The issuance of the Series A Preferred Stock to EagleEnergy pursuant to the Eagle Purchase Agreement was approved by our stockholders holding a majority of the outstanding shares of our commonstock.Cash Flows from Operating, Investing and Financing Activities The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods presented (dollars inthousands). For information regarding the individual components of our cash flow amounts, please refer to the Audited Consolidated Statements ofCash Flows included under Item 15 of this Annual Report.76 For the Years Ended December 31, 2013 2012 2011 Net cash provided by operating activities $227,102 $137,249 $141,550 Net cash used in investing activities (1,193,846) (773,608) (242,619)Net cash provided by financing activities 981,029 647,893 96,496 Net change in cash $14,285 $11,534 $(4,573) Table of Contents Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil, NGLs and natural gas prices.Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices ofthese commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on ourfinancial position, see "Item 7A.—Quantitative and Qualitative Disclosures About Market Risk" beginning on page 80. The following information highlights the significant period-to-period variances in our cash flow amounts:Cash flows provided by operating activities Net cash provided by operating activities was $227.1 million, $137.2 million and $141.6 million for the years ended December 31, 2013, 2012 and2011, respectively. The increase in net cash provided by operating activities for the year ended December 31, 2013 compared to the year endedDecember 31, 2012 was primarily driven by an increase in production in all commodities and an increase in natural gas prices, offset by a decrease in oiland NGL prices. The slight decrease in net cash provided by operating activities for the year ended December 31, 2012 compared to the year endedDecember 31, 2011 was primarily driven by a decrease in oil, natural gas and natural gas liquids prices, partially offset by an increase in production.Cash flows used in investing activities We had net cash used in investing activities of $1.2 billion, $773.6 million and $242.6 million during the years ended December 31, 2013, 2012and 2011, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The increase in in net cash used ininvesting activities during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to the Anadarko BasinAcquisition and continued expansion of our drilling programs. The increase in net cash used in investing activities during the year ended December 31,2012 compared to the year ended December 31, 2011 was primarily due to the Eagle Property Acquisition and continued expansion of our drillingprograms and growth of our business.Cash flows provided by financing activities Net cash provided by financing activities was $981.0 million, $647.9 million and $96.5 million for the years ended December 31, 2013, 2012 and2011, respectively. For the year ended December 31, 2013, cash sourced through financing activities was provided primarily from net long-termborrowings of $1.0 billion, consisting of the 2021 Senior Notes of $700 million and borrowings under the revolver of $341.5 million, offset byrepayments of our revolving credit facility of $34.3 million. For the year ended December 31, 2012, cash sourced through financing activities was provided primarily from proceeds from our initial publicoffering of $213.6 million and net long-term borrowings of $459.2 million, consisting of the 2020 Senior Notes of $600 million and advances from ourrevolving credit facility, offset by repayments of our revolving credit facility during the year. For years prior to 2012, cash sourced through financingactivities was provided primarily by First Reserve and members of our management and borrowings under our revolving credit facility. Our long-termdebt was $1.7 billion, $694.0 million and $234.8 million at December 31, 2013, 2012 and 2011, respectively.77Table of ContentsOther ItemsObligations and commitments We have the following contractual obligations and commitments as of December 31, 2013 (in thousands):Critical Accounting Policies and Estimates We prepare our financial statements and the accompanying notes in conformity with GAAP, which requires our management to make estimatesand assumptions about future events that affect the reported amounts in our financial statements and the accompanying notes. We identify certainaccounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations or liquidity andthe degree of difficulty, subjectivity and complexity in their deployment. Critical accounting policies cover accounting matters that are inherentlyuncertain because the future resolution of such matters is unknown. Our management routinely discusses the development, selection and disclosure ofeach of the critical accounting policies. Following is a discussion of our most critical accounting policies: Reserves Estimates. Proved oil and gas reserves are the estimated quantities of natural gas, crude oil and NGLs that geological and engineeringdata demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing operating conditions and governmentregulations. Proved undeveloped reserves include those reserves that are expected to be recovered from78 Payments due by Period Total 1 - 3 years 4 - 5 years More than5 years Revolving credit facility(1) $401,150 $— $401,150 $— 2020 Senior Notes(2) 1,035,375 193,500 129,000 712,875 2021 Senior Notes(2) 1,185,625 194,250 129,500 861,875 Drilling contracts(3) 8,192 8,192 — — Operating leases(3) 11,052 5,466 3,412 2,174 Seismic contracts(3) 4,410 4,410 — — Asset retirement obligations(4) 26,308 — — 26,308 Total contractual obligations $2,672,112 $405,818 $663,062 $1,603,232 (1)Amount excludes interest on our revolving credit facility as both the amount borrowed and applicable interest rate isvariable. As of December 31, 2013, we had $401.2 million of indebtedness outstanding under our revolving creditfacility. See Note 8 to our Consolidated Financial Statements. (2)Amount includes approximately $64.5 million and $65.8 million of interest per year for our 2020 Senior Notes and 2021Senior Notes, respectively; see Note 8 to our Consolidated Financial Statements. (3)See Note 14 to our Consolidated Financial Statements for a description of operating lease, drilling contract, seismiccontract and other obligations. (4)Amounts represent our estimate of future asset retirement obligations on a discounted basis. Because these costs typicallyextend many years into the future, estimating these future costs requires management to make estimates and judgmentsthat are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology andthe political and regulatory environment. See Note 7 to our Consolidated Financial Statements.Table of Contentsnew wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may beclassified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or wherereliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves onlyif a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longertime. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since weuse the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Ouroil and gas properties are also subject to a "ceiling" limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basisfor our supplemental oil and gas disclosures. Reserves as of December 31, 2013, 2012 and 2011 were calculated using an unweighted arithmetic average of commodity prices in effect on thefirst day of each month, held flat for the life of the production, except where prices are defined by contractual arrangements. We have elected not to disclose probable and possible reserves or reserve estimates in this filing. Revenue Recognition. Our revenue recognition policy is significant because revenue is a key component of the results of operations and of theforward-looking statements contained in the analysis of liquidity and capital resources. We record revenue in the month our production is delivered tothe purchaser, but payment is generally received 30 to 90 days after the date of production. At the end of each month, we estimate the amount ofproduction that was delivered to the purchaser and the price that will be received. We use our knowledge of our properties, their historical performance,the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices and other factors as the basis forthese estimates. We record the variances between our estimates and the actual amounts received in the month payment is received. Share-Based Compensation. We account for share-based compensation awards in accordance with FASB ASC 718, Compensation—StockCompensation. We measure share-based compensation cost at fair value and generally recognize the corresponding compensation expense on a straight-line basis over the service period during which awards are expected to vest. We include share-based compensation expense in "General andadministrative expense" in our consolidated statements of operations. Financial Instruments. Our financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivatives.Commodity derivatives are recorded at fair value. The carrying amount of our other financial instruments approximate fair value because of the short-term nature of the items or variable pricing. Derivative financial instruments are recorded in our consolidated balance sheets as either an asset or liability measured at estimated fair value.Changes in the derivative's fair value are recognized currently in earnings as gains and losses in the period of change. The gains or losses are recordedwithin revenues in "Losses on commodity derivative contracts—net." The related cash flow impact is reflected within cash flows from operatingactivities. Asset Retirement Obligations. We have obligations to remove tangible equipment and facilities associated with our oil and natural gas wells, andto restore land at the end of oil and natural gas production operations. The removal and restoration obligations are associated with plugging andabandoning wells. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of theremoval obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removaltechnologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in thepresent value calculations are numerous assumptions79Table of Contentsand judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal,regulatory, environmental and political environments.ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address theserisks through a program of risk management including the use of derivative instruments. Commodity price exposure. We are exposed to market risk as the prices of oil and natural gas fluctuate due to changes in supply and demand. Topartially reduce price risk caused by these market fluctuations, we have hedged in the past a portion of our production and expect to continue hedging asignificant portion of our future production. We utilize derivative financial instruments to manage risks related to changes in oil, NGLs and natural gas prices. As of December 31, 2013, weutilized fixed price swaps, collars and basis differential swaps to reduce the volatility of oil, NGLs and natural gas prices on a portion of our futureexpected production. For derivative instruments recorded at fair value, the credit standing of our counterparties is analyzed and factored into the fair value amountsrecognized on the balance sheet. The following is a summary of our commodity derivative contracts as of December 31, 2013:80 HedgedVolume Weighted-AverageFixed PriceOil (Bbls): WTI Swaps—2014 4,344,450 $88.76WTI Swaps—2015 1,820,000 $86.55WTI Collars—2014 164,400 $88.49 - $97.94WTI to LLS Basis Differential Swaps—2014(1) 501,000 $5.35NGL (Bbls): NGL Swaps—2014 151,500 $62.16Natural Gas (MMBtu): Swaps—2014(2) 17,885,000 $4.17Swaps—2015 18,250,000 $4.13Collars—2014(3) 1,685,004 $3.99 - $5.09(1)We enter into swap arrangements intended to preserve the positive differential between LLS pricing and NYMEX WTIpricing. (2)Includes 1,519,000 MMBtu that priced in the fourth quarter of 2013, but had not cash settled as of December 31, 2013. (3)Includes 64,667 MMBtu that priced in the fourth quarter of 2013, but had not cash settled as of December 31, 2013.Table of Contents As of December 31, 2013, 2012 and 2011, assets and liabilities recorded at fair value in the balance sheets were categorized based upon the levelof judgment associated with the inputs used to measure their value. Our only financial assets and liabilities that are measured at fair value on a recurringbasis as of December 31, 2013, 2012 and 2011 are the derivative instruments discussed above. At December 31, 2013 and 2012, all of our commodityderivative contracts were with seven and five bank counterparties, respectively, and are all classified as Level 2. Our policy is to net derivative liabilitiesand assets where there is a legally enforceable master netting agreement with the counterparty. Interest rate risk. At December 31, 2013, we had indebtedness outstanding under our credit facility of $401.2 million, which bore interest atfloating rates; we had $600 million outstanding in 2020 Senior Notes, which bore interest at 10.75%; and $700 million outstanding in 2021 SeniorNotes which bore interest at 9.25%. The average annual interest rate incurred on this indebtedness for the years ended December 31, 2013, 2012 and2011 was approximately 8.7%, 6.7% and 3.2%, respectively. A 1.0% increase in each of the average LIBOR and federal funds rate for the years endedDecember 31, 2013 and 2012 would have resulted in an estimated $2.1 million and $1.5 million, respectively, increase in interest expense, of which aportion may be capitalized. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues.Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. At December 31,2013, we do not have any interest rate derivatives in place. Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate.These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to controlparticipation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers,including ConocoPhillips, Chevron and Gulfmark. See "Business—Marketing and Major Customers" on page 22 for further detail about our significantcustomers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect ourfinancial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing ofour significant customers for oil and 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. Thecounterparties on our current derivative instruments are lenders under our revolving credit facility with investment grade ratings, and we are likely toenter into any future derivative instruments with these or other lenders under our revolving credit facility which also carry investment grade ratings.Several of our significant customers for oil and gas receivables have a credit rating below investment grade or do not have rated debt securities. In thesecircumstances, we81 For the Year EndedDecember 31, 2013 (in thousands) Derivative fair value at period end—liability (included in balance sheet) $(30,812) Realized net loss (included in the statement of operations) $(17,585) Unrealized net loss (included in the statement of operations) $(26,699) Table of Contentshave considered the lack of investment grade credit rating in addition to the other factors described above. Off-Balance Sheet Arrangements. Currently, we do not have any off-balance sheet arrangements.ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm begin on page F-1 of thisAnnual Report.ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.ITEM 9A. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under thesupervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness ofthe design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the endof the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the informationrequired to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including ourprincipal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded,processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principalexecutive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at December 31, 2013 atthe reasonable assurance level due to the material weakness discussed below. Management's Annual Report on Internal Control over Financial Reporting. The management of the Company is responsible forestablishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f).Internal control over financial reporting is defined as a process designed by, or under the supervision of, the issuer's principal executive and principalfinancial officer's, or persons performing similar functions, and effected by the Company's board of directors, management, and other personnel, toprovide reasonable assurance regarding reliability of financial reporting and the preparation of financial statements for external purposes in accordancewith generally accepted accounting principles and includes those policies and procedures which (a) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions and dispositions of assets of the Company, (b) provide reasonable assurance thattransactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and thatreceipts and expenditures are being made only in accordance with authorizations of management and the board of directors, and (c) provide reasonableassurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on thefinancial statements. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is areasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, weconducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of The Treadway Commission. Based on our82Table of Contentsevaluation under the Internal Control Integrated Framework (2013), our management concluded that our internal control over financial reporting wasnot effective as of December 31, 2013 as a result of a material weakness described below. Internal control over the preparation of oil and gas reserve estimates. We did not maintain effective internal control over the accuracy andvaluation of oil and gas reserves estimates. Specifically, controls were not operating effectively over the validation of the accuracy and completeness ofcertain source data provided to the independent third party reserve engineers, or perform adequate management review of the independent third partyreserves report to determine if reserves estimates were complete and consistent with management's capital spending plans. These control deficienciesresulted in errors that, if not corrected, would have resulted in the misstatement of disclosures related to the value of oil and gas properties andassociated reserves estimates, which impacts our calculation of depletion of the cost of our oil and gas properties and the amount of our impairment ofoil and gas properties, and the standardized measures of oil and gas. 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 thedegree of compliance with the policies or procedures may deteriorate. Deloitte & Touche LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Companyincluded in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company's internal control over financial reporting atDecember 31, 2013. The report, which expresses an adverse opinion on the effectiveness of the Company's internal control over financial reporting, isincluded in this Item under the heading "Report of Independent Registered Public Accounting Firm." Changes in internal control over financial reporting. During the quarter ended December 31, 2013, we completed the conversion to newaccounting and land software. We took the necessary steps to monitor and maintain appropriate internal controls during this period of change. Thesesteps included procedures to preserve the integrity of the data converted and a review by management to validate the data converted. Additionally, weprovided training related to this system to individuals using the system to carry out their job responsibilities. We anticipate that the implementation ofthis software will strengthen the overall system of internal controls due to enhanced automation of workflow and controls, and further integration ofrelated processes. We completed the design and documentation of internal control processes and procedures relating to the new system and modules tosupplement and complement existing internal controls over certain respective job areas. Testing of the controls related to the new system implementationhas been completed and was included in the scope of our assessment of internal control over financial reporting for 2013. Management's plan for remediation of our material weakness. In response to the identified material weakness, our management, withoversight from our Audit Committee, is taking the following actions to remediate the material weakness related to the calculation of oil and gas reservesestimates described above:•Redesign controls over management's review of reserves estimates to ensure an appropriate level of precision to address the associatedrisks; •Further expand documentation of the procedures for reviewing data used as inputs into the reserve report calculations and for retainingevidence when such review is performed; •Implement a process for documenting the key decisions and assumptions made by Company operations personnel during thereconciliation of reserves output between management's internal calculations and the outside reserve engineering firm's calculations; and •Train the reserves engineering staff on the above procedures.83Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Midstates Petroleum Company, Inc.Houston, Texas We have audited the internal control over financial reporting of Midstates Petroleum Company, Inc. and subsidiary ("Midstates") as ofDecember 31, 2013, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of SponsoringOrganizations of the Treadway Commission. Midstates' management is responsible for maintaining effective internal control over financial reportingand for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on InternalControl over Financial Reporting. Our responsibility is to express an opinion on Midstates' internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting wasmaintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that amaterial weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performingsuch other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive andprincipal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnelto provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes inaccordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and proceduresthat (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of thecompany; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance withgenerally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations ofmanagement and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition,use, or disposition of the company's assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper managementoverride of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluationof the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequatebecause of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonablepossibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. Thefollowing material weakness has been identified and included in management's assessment: internal controls over the preparation of oil and gas reserveestimates. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidatedfinancial statements as of and for the year ended December 31, 2013, of Midstates and this report does not affect our report on such financialstatements.84Table of Contents In our opinion, because of the effect of the material weakness identified above on the achievement of the objectives of the control criteria, theCompany has not maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteriaestablished in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidatedfinancial statements as of and for the year ended December 31, 2013 of Midstates and our report dated March 24, 2014 expressed an unqualifiedopinion on those consolidated financial statements./s/ DELOITTE & TOUCHE LLPHouston, TexasMarch 24, 201485Table of ContentsITEM 9B. OTHER INFORMATION None.PART III. ITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitiveproxy statement for our 2014 Annual Meeting of Stockholders.ITEM 11. EXECUTIVE COMPENSATION Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitiveproxy statement for our 2014 Annual Meeting of Stockholders.ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDERS Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitiveproxy statement for our 2014 Annual Meeting of Stockholders.ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitiveproxy statement for our 2014 Annual Meeting of Stockholders.ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitiveproxy statement for our 2014 Annual Meeting of Stockholders.PART IV. ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES (a)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.86Table of Contents(3)Exhibits: The following documents are included as exhibits to this report:87 2.1 Master Reorganization Agreement, dated April 24, 2012, by and among the Company and certain ofits affiliates, certain members of the Company's management and certain affiliates of First ReserveCorporation (filed as Exhibit 2.1 to the Company's Current Report on Form 8-K filed on April 25,2012, and incorporated herein by reference). 2.2 Purchase and Sale Agreement, dated as of April 3, 2013, by and among Midstates PetroleumCompany LLC, Panther Energy Company, LLC, Red Willow Mid-Continent, LLC and Linn EnergyHoldings, LLC (filed as Exhibit 2.1 to the Company's Current Report on Form 8-K filed on April 4,2013, and incorporated herein by reference). 3.1 Amended and Restated Certificate of Incorporation of Midstates Petroleum Company, Inc. (filed asExhibit 3.1 to the Company's Current Report on Form 8-K filed on April 25, 2012, and incorporatedherein by reference). 3.2 Amended and Restated Bylaws of Midstates Petroleum Company, Inc. (filed as Exhibit 3.2 to theCompany's Current Report on Form 8-K filed on April 25, 2012, and incorporated herein byreference). 3.3 Certificate of Designations of Series A Mandatorily Convertible Preferred Stock of MidstatesPetroleum Company, Inc. (filed as Exhibit 3.1 to the Company's Current Report on Form 8-K filed onOctober 2, 2012, and incorporated herein by reference). 4.1 Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company's Registration Statement onForm S-1/A on February 29, 2012, and incorporated herein by reference). 4.2 Indenture, dated October 1, 2012, by and among the Company, Midstates Petroleum Company LLCand Wells Fargo Bank, National Association, as trustee, governing the 10.75% senior notes due 2020(filed as Exhibit 4.1 to the Company's Current Report on Form 8-K filed on October 2, 2012, andincorporated herein by reference). 4.3 Registration Rights Agreement, dated October 1, 2012, by and among the Company, MidstatesPetroleum Company LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representativeof the several initial purchasers named therein, relating to the 10.75% senior notes due 2020 (filed asExhibit 4.2 to the Company's Current Report on Form 8-K filed on October 2, 2012, and incorporatedherein by reference). 4.4 Registration Rights Agreement, dated October 1, 2012, by and among the Company, Eagle EnergyProduction, LLC, FR Midstates Interholding, LP and certain other of the Company's stockholders(filed as Exhibit 4.3 to the Company's Current Report on Form 8-K filed on October 2, 2012, andincorporated herein by reference). 4.5 Indenture, dated May 31, 2013, by and among the Midstates Petroleum Company, Inc., MidstatesPetroleum Company LLC and the Well Fargo Bank, National Association, as trustee, governing the9.25% senior notes due 2021 (filed as Exhibit 4.1 to the Company's Current Report on Form 8-K filedon June 3, 2013, and incorporated herein by reference). Table of Contents88 4.6 Registration Rights Agreement, dated May 31, 2013, by and among the Midstates PetroleumCompany, Inc., Midstates Petroleum Company LLC and Morgan Stanley & Co. LLC and SunTrustRobinson Humphrey, Inc., as representatives of the several initial purchasers named therein, relating tothe 9.25% senior notes due 2021 (filed as Exhibit 4.2 to the Company's Current Report on Form 8-Kfiled on June 3, 2013, and incorporated herein by reference). 10.1 Stockholders' Agreement among the Company and certain equity owners (filed as Exhibit 10.1 to theCompany's Current Report on Form 8-K filed on April 25, 2012, and incorporated herein byreference). 10.2 Second Amended and Restated Credit Agreement, dated as of June 8, 2012, among the Company,Midstates Petroleum Company LLC, SunTrust Bank as administrative agent and the other lenderparties thereto (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on June 13,2012, and incorporated herein by reference). 10.3 Assignment and First Amendment to the Second Amended and Restated Credit Agreement, dated asof September 7, 2012, among the Company, Midstates Petroleum Company LLC, SunTrust Bank asadministrative agent and the other lenders and parties party thereto (filed as Exhibit 10.1 to theCompany's Current Report on Form 8-K filed on September 12, 2012, and incorporated herein byreference). 10.4 Amendment to First Amendment to the Second Amended and Restated Credit Agreement, dated as ofSeptember 26, 2012, among the Company, Midstates Petroleum Company LLC, SunTrust Bank, asadministrative agent, and the other lenders and parties party thereto (filed as Exhibit 10.1 to theCompany's Current Report on Form 8-K filed on September 27, 2012, and incorporated herein byreference). 10.5 Second Amendment to Second Amended and Restated Credit Agreement, dated as of March 19, 2013,among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, SunTrust Bank, asadministrative agent, and the other lenders party thereto (filed as Exhibit 10.1 to the Company'sCurrent Report on Form 8-K filed on March 22, 2013, and incorporated herein by reference). 10.6 Assignment and Third Amendment to the Second Amended and Restated Credit Agreement, dated asof May 20, 2013, among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC,SunTrust Bank as administrative agent and the other lenders and parties party thereto (filed asExhibit 10.1 to the Company's Current Report on Form 8-K filed on May 22, 2013, and incorporatedherein by reference). 10.7 Assignment and Fourth Amendment to the Second Amended and Restated Credit Agreement, dated asof September 26, 2013, among Midstates Petroleum Company, Inc., Midstates PetroleumCompany LLC, SunTrust Bank as administrative agent and the other lenders and parties party thereto(filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on September 30, 2013, andincorporated herein by reference). 10.8 Asset Purchase Agreement, dated as of August 11, 2012, among the Company, Midstates PetroleumCompany, LLC and Eagle Energy Production, LLC (filed as Exhibit 2.1 to the Company's CurrentReport on Form 8-K filed on August 13, 2012, and incorporated herein by reference). 10.9**Executive Employment Agreement dated as of April 25, 2012 between the Company and John A.Crum (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed on April 30, 2012,and incorporated herein by reference). Table of Contents 10.10(a)**Executive Employment Agreement dated as of April 25, 2012 between the Company and NelsonHaight. 10.11(a)**Amendment to Executive Employment Agreement dated as of December 12, 2013 between theCompany and Nelson Haight. 10.12(a)**Executive Employment Agreement dated as of April 25, 2012 between the Company and Curtis A.Newstrom. 10.13(a)**Executive Employment Agreement dated as of April 25, 2012 between the Company and DexterBurleigh. 10.14**Executive Employment Agreement dated as of April 25, 2012 between the Company and Thomas L.Mitchell (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed on April 30, 2012,and incorporated herein by reference). 10.15**Executive Employment Agreement dated as of April 25, 2012 between the Company and Stephen C.Pugh (filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed on April 30, 2012,and incorporated herein by reference). 10.16**Separation and Release Agreement, dated as of October 3, 2013 between Midstates PetroleumCompany, Inc. and Stephen C. Pugh (filed as Exhibit 10.1 to the Company's Current Report onForm 8-K filed on October 4, 2013, and incorporated herein by reference). 10.17**Midstates Petroleum Company Inc. 2012 Long Term Incentive Plan (filed as Exhibit 4.3 to theCompany's Registration Statement on Form S-8 on April 20, 2012, and incorporated herein byreference). 10.18**Midstates Petroleum Company, Inc. 2012 Long-Term Incentive Plan Form of Restricted StockAgreement (Time Vesting) for 2012 Awards (filed as Exhibit 10.10 to the Company's RegistrationStatement on Form S-1/A on January 20, 2012, and incorporated herein by reference). 10.19**Midstates Petroleum Company, Inc. 2012 Long-Term Incentive Plan Form of Restricted StockAgreement (Time Vesting) for 2013 Awards (filed as Exhibit 10.1 to the Company's Current Reporton Form 8-K filed on February 27, 2013, and incorporated herein by reference). 10.20**Midstates Petroleum Company, Inc. Form of Notice of Grant of Restricted Stock (Time Vesting) (filedas Exhibit 10.11 to the Company's Registration Statement on Form S-1/A on January 20, 2012, andincorporated herein by reference). 10.21**Form of Indemnification Agreement between the Company and each of the directors and executiveofficers thereof (filed as Exhibit 10.12 to the Company's Registration Statement on Form S-1/A onFebruary 16, 2012, and incorporated herein by reference). 12.1(a)Statement of Computation of Ratio of Earnings to Fixed Charges 21.1(a)List of subsidiaries of the Company. 23.1(a)Consent of Deloitte & Touche LLP. 23.2(a)Consent of Netherland, Sewell and Associates, Inc.—Independent Petroleum Engineers 23.3(a)Consent of Cawley, Gillespie & Associates, Inc.—Independent Petroleum Engineers 89 31.1(a)Sarbanes-Oxley Section 302 certification of Principal Executive Officer. 31.2(a)Sarbanes-Oxley Section 302 certification of Principal Financial Officer.Table of Contents90 32.1(b)Sarbanes-Oxley Section 906 certification of Principal Executive Officer. 32.2(b)Sarbanes-Oxley Section 906 certification of Principal Financial Officer. 99.1(a)Report of Netherland, Sewell & Associates, Inc. 99.2(a)Report of Cawley, Gillespie & Associates, Inc. 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 arrangementTable of ContentsSIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to besigned on its behalf by the undersigned, hereunto duly authorized.Dated: March 24, 2014 KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints John A. Crum,Nelson M. Haight and Eric J. Christ, each of whom may act without joinder of the other, as their true and lawful attorneys-in-fact and agents, each withfull power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign any and allamendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto and other documents in connection therewith, with theSecurities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act andthing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, herebyratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant 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 capacities and on the dates indicated.91 MIDSTATES PETROLEUM COMPANY, INC. /s/ JOHN A. CRUMJohn A. CrumPresident, Chief Executive Officer andChairman of the BoardSignatures Title Date /s/ JOHN A. CRUMJohn A. Crum Chairman, President and Chief ExecutiveOfficer (principal executive officer) March 24, 2014/s/ NELSON M. HAIGHTNelson M. Haight Senior Vice President and Chief FinancialOfficer (principal financial and accountingofficer) March 24, 2014/s/ ANASTASIA DEULINAAnastasia Deulina Director March 24, 2014/s/ DR. PETER J. HILLDr. Peter J. Hill Director March 24, 2014Table of Contents92Signatures Title Date /s/ THOMAS C. KNUDSONThomas C. Knudson Director March 24, 2014/s/ LOREN M. LEIKERLoren M. Leiker Director March 24, 2014/s/ STEPHEN J. MCDANIELStephen J. McDaniel Director March 24, 2014/s/ JOHN MOGFORDJohn Mogford Director March 24, 2014/s/ MARY P. RICCIARDELLOMary P. Ricciardello Director March 24, 2014/s/ ROBERT M. TICHIORobert M. Tichio Director March 24, 2014Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.INDEX TO CONSOLIDATED FINANCIAL STATEMENTS F-1 Page Report of Independent Registered Public Accounting Firm F-2 Consolidated balance sheets as of December 31, 2013 and 2012 F-3 Consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011 F-4 Consolidated statement of changes in stockholders'/members' equity for the years ended December 31, 2013,2012 and 2011 F-5 Consolidated statements of cash flows for the years ended December 31, 2013, 2012 and 2011 F-6 Notes to consolidated financial statements F-7 Supplemental oil and gas information (unaudited) F-42 Selected quarterly financial data (unaudited) F-48 Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and Stockholders of Midstates Petroleum Company, Inc.Houston, Texas We have audited the accompanying consolidated balance sheets of Midstates Petroleum Company, Inc. and subsidiary ("Midstates") as ofDecember 31, 2013 and 2012, and the related consolidated statements of operations, stockholders'/members' equity, and cash flows for each of the threeyears in the period ended December 31, 2013. These financial statements are the responsibility of Midstates' management. Our responsibility is toexpress an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Anaudit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessingthe accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. Webelieve that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Midstates PetroleumCompany, Inc. and subsidiary as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years inthe period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Midstates' internalcontrol over financial reporting as of December 31, 2013, based on the criteria established in Internal Control—Integrated Framework (2013) issuedby the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 24, 2014 expressed an adverse opinion onMidstates' internal control over financial reporting because of a material weakness./s/ DELOITTE & TOUCHE LLPHouston, TexasMarch 24, 2014F-2Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.CONSOLIDATED BALANCE SHEETS(In thousands, except share amounts) December 31,2013 December 31,2012 ASSETS CURRENT ASSETS: Cash and cash equivalents $33,163 $18,878 Accounts receivable: Oil and gas sales 102,483 35,618 Joint interest billing 42,631 10,815 Other 1,090 3,866 Commodity derivative contracts 700 5,695 Deferred income taxes 11,837 6,027 Other current assets 693 8,573 Total current assets 192,597 89,472 PROPERTY AND EQUIPMENT: Oil and gas properties, on the basis of full-cost accounting 3,060,661 1,836,664 Other property and equipment 11,113 5,038 Less accumulated depreciation, depletion, amortization and impairment (976,880) (274,294) Net property and equipment 2,094,894 1,567,408 OTHER ASSETS: Commodity derivative contracts 19 1,717 Other noncurrent assets 54,597 25,413 Total other assets 54,616 27,130 TOTAL $2,342,107 $1,684,010 LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable $21,493 $29,196 Accrued liabilities 204,381 98,649 Commodity derivative contracts 27,880 7,582 Total current liabilities 253,754 135,427 LONG-TERM LIABILITIES: Asset retirement obligations 26,308 15,245 Commodity derivative contracts 3,651 3,943 Long-term debt 1,701,150 694,000 Deferred income taxes 15,291 156,737 Other long-term liabilities 1,954 1,189 Total long-term liabilities 1,748,354 871,114 COMMITMENTS AND CONTINGENCIES (Note 14) STOCKHOLDERS' EQUITY Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding — — Series A mandatorily convertible preferred stock, $0.01 par value, $358,550 and $325,000 liquidationvalue at December 31, 2013 and December 31, 2012, respectively; 8% cumulative dividends; 325,000shares issued and outstanding 3 3 Common stock, $0.01 par value, 300,000,000 shares authorized; 68,925,745 shares issued and 68,807,043shares outstanding at December 31, 2013 and 66,619,711 shares issued and outstanding at December 31,2012 689 666 Treasury stock (664) — Additional paid-in-capital 871,047 863,891 Retained deficit (531,076) (187,091) Total stockholders' equity 339,999 677,469 TOTAL $2,342,107 $1,684,010 The accompanying notes are an integral part of these consolidated financial statements.F-3Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.CONSOLIDATED STATEMENTS OF OPERATIONS(In thousands, except per share amounts) The accompanying notes are an integral part of these consolidated financial statements. Years Ended December 31, 2013 2012 2011 REVENUES: Oil sales $387,226 $218,430 $177,464 Natural gas liquid sales 62,340 23,617 15,683 Natural gas sales 63,187 16,030 20,665 Losses on commodity derivative contracts—net (44,284) (11,158) (4,844)Other 1,037 754 465 Total revenues 469,506 247,673 209,433 EXPENSES: Lease operating and workover 73,414 30,500 16,117 Gathering and transportation 5,455 — — Severance and other taxes 27,237 24,921 13,640 Asset retirement accretion 1,435 723 334 Depreciation, depletion, and amortization 250,396 125,561 91,699 Impairment in carrying value of oil and gas properties 453,310 — — General and administrative 53,250 30,541 68,915 Acquisition and transaction costs 11,803 14,884 — Other 615 — — Total expenses 876,915 227,130 190,705 OPERATING INCOME (LOSS) (407,409) 20,543 18,728 OTHER INCOME (EXPENSE) Interest income 33 245 23 Interest expense—net of amounts capitalized (83,138) (12,999) (2,094) Total other income (expense) (83,105) (12,754) (2,071) INCOME (LOSS) BEFORE TAXES (490,514) 7,789 16,657 Income tax benefit (expense) 146,529 (157,886) — NET INCOME (LOSS) $(343,985)$(150,097)$16,657 Preferred stock dividend (15,589) (6,500) — Participating securities—Series A Preferred Stock — — — Participating securities—Non-vested Restricted Stock — — — NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $(359,574)$(156,597)$16,657 Basic and diluted net loss per share attributable to common shareholders $(5.47)$(2.61) N/A Basic and diluted weighted average number of common shares outstanding 65,766 59,979 N/A F-4Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS'/MEMBERS' EQUITY(See Note 10 for Share History)(In thousands) Series APreferredStock CommonStock TreasuryStock CapitalContributions AdditionalPaid-in-Capital RetainedDeficit/AccumulatedLoss TotalStockholders'Equity Balance as ofJanuary 1, 2011 $— $— $— $309,530 $— $(53,651)$255,879 Distribution tomembers — — — (50,572) — — (50,572)Members'contribution — — — 2,870 — — 2,870 Reclassificationof liability forshare-basedawards — — — 60,668 — — 60,668 Net income — — — — — 16,657 16,657 Balance as ofDecember 31,2011 $— $— $— $322,496 $— $(36,994)$285,502 Issuance ofcommon stock — 476 — (476) — — — Reclassificationof members'contributions — — — (322,020) 322,020 — — Proceeds fromthe sale ofcommon stock 180 — — 213,389 — 213,569 Tax attributescontributed atIPOreorganizationdate byshareholdingentities — — — — 33,888 33,888 Issuance ofpreferred stockasconsiderationin the EaglePropertyAcquisition 3 — — — 291,953 — 291,956 Share-basedcompensation — 10 — — 2,641 — 2,651 Net loss — — — — — (150,097) (150,097) Balance as ofDecember 31, The accompanying notes are an integral part of these consolidated financial statements.F-52012 $3 $666 $— $— $863,891 $(187,091)$677,469 Share-basedcompensation — 23 — — 7,156 — 7,179 Acquisition oftreasury stock — — (664) — — — (664)Net loss — — — — — (343,985) (343,985) Balance as ofDecember 31,2013 $3 $689 $(664)$— $871,047 $(531,076)$339,999 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.CONSOLIDATED STATEMENTS OF CASH FLOWS(In thousands) The accompanying notes are an integral part of these consolidated financial statements. Years Ended December 31, 2013 2012 2011 CASH FLOWS FROM OPERATING ACTIVITIES: Net loss $(343,985)$(150,097)$16,657 Adjustments to reconcile net loss to net cash provided by operating activities: Losses on commodity derivative contracts—net 44,284 11,158 4,844 Net cash paid for commodity derivative contracts not designated as hedging instruments (17,585) (15,825) (16,733)Asset retirement accretion 1,435 723 334 Depreciation, depletion, and amortization 250,396 125,561 91,699 Impairment in carrying value of oil and gas properties 453,310 — — Share-based compensation, net of amounts capitalized to oil and gas properties 5,713 2,459 53,744 Deferred income taxes (146,529) 157,886 — Amortization of deferred financing costs 5,955 1,530 850 Change in operating assets and liabilities: Accounts receivable—oil and gas sales (66,865) (11,826) (9,651)Accounts receivable—JIB and other (28,488) (11,019) (3,125)Other current and noncurrent assets (1,802) (218) (6,799)Accounts payable (4,350) (646) 3,059 Accrued liabilities 75,903 27,931 5,977 Other (290) (368) 694 Net cash provided by operating activities $227,102 $137,249 $141,550 CASH FLOWS FROM INVESTING ACTIVITIES: Investment in property and equipment (573,734) (422,332) (242,619)Investment in acquired property (620,112) (351,276) — Net cash used in investing activities $(1,193,846)$(773,608)$(242,619) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings 1,041,450 744,667 145,200 Repayment of long-term borrowings (34,300) (285,467) — Proceeds from issuance of mandatorily redeemable convertible preferred units — 65,000 — Repayment of mandatorily redeemable convertible preferred units — (65,000) — Proceeds from sale of common stock, net of initial public offering expenses of $6.4 million — 213,569 — Deferred financing costs (25,457) (24,876) (863)Acquisition of treasury stock (664) — — Cash received for units, pre-IPO — — 2,870 Distributions to members — — (50,572)Other — — (139) Net cash provided by financing activities $981,029 $647,893 $96,496 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 14,285 11,534 (4,573)Cash and cash equivalents, beginning of period $18,878 $7,344 $11,917 Cash and cash equivalents, end of period $33,163 $18,878 $7,344 SUPPLEMENTAL INFORMATION: Non-cash transactions—investments in property and equipment accrued—not paid $106,500 $87,812 $61,590 Non-cash components of Eagle Property Acquisition Purchase Price: —Preferred stock issued for property — 291,956 — —Deferred tax liability assumed (727) 26,712 — —Asset retirement obligation assumed — 2,662 — —Accrual for additional consideration (941) 1,500 — Non-cash components of Anadarko Basin Acquisition Purchase Price: —Asset retirement obligations assumed 6,296 — — —Accrual for miscellaneous liabilities assumed 3,030 — — Cash paid for interest, net of capitalized interest of $32.2 million, $11.2 million and $2.6 million,respectively 72,085 — 1,594 Tax attributes contributed at IPO reorganization date by shareholding entities — 33,888 — Reclassification of share-based compensation to members' equity — — 6,924 F-6Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements1. Organization and Business Midstates Petroleum Company, Inc., through its wholly-owned subsidiary Midstates Petroleum Company LLC, engages in the business of drillingfor, and production of, oil, natural gas and natural gas liquids. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State ofDelaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC ("Midstates Sub"), which was previously awholly-owned subsidiary of Midstates Petroleum Holdings LLC ("Holdings LLC"). Pursuant to the terms of a corporate reorganization that wascompleted in connection with the closing of Midstates Petroleum Company, Inc.'s initial public offering, all of the interests in Midstates PetroleumHoldings LLC were exchanged for newly issued common shares of Midstates Petroleum Company, Inc., and as a result, Midstates PetroleumCompany LLC became a wholly-owned subsidiary of Midstates Petroleum Company, Inc. and Midstates Petroleum Holdings LLC ceased to exist as aseparate entity. The terms "the Company," "we," "us," "our," and similar terms when used in the present tense, prospectively or for historical periodssince April 25, 2012, refer to Midstates Petroleum Company, Inc. and its subsidiary, and for historical periods prior to April 25, 2012, refer toMidstates Petroleum Holdings LLC and its subsidiary, unless the context indicates otherwise. The term "Holdings LLC" refers solely to MidstatesPetroleum Holdings LLC prior to the corporate reorganization. On April 25, 2012, the Company completed its initial public offering of common stock pursuant to a registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Pursuant to the registration statement, the Company registered the offer andsale of 27,600,000 shares of $0.01 par value common stock, which included 6,000,000 shares of stock sold by the selling shareholders and 3,600,000shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments. The Company'ssale of the shares in its initial public offering closed on April 25, 2012 and its initial public offering terminated upon completion of the closing. The proceeds of the Company's initial public offering, based on the public offering price of $13.00 per share, were approximately $358.8 million.After subtracting underwriting discounts and commissions of $21.5 million and the net proceeds to the selling stockholders of $117.3 million, theCompany received net proceeds of approximately $220.0 million from the registration and sale of 18,000,000 common shares (or $213.6 million net ofoffering expenses paid directly by the Company). The Company used $67.1 million of the net proceeds to redeem convertible preferred units inHoldings LLC, including interest and other charges, and $99.0 million to pay down a portion of the borrowings under its revolving credit facility. TheCompany used the remaining $47.5 million to fund the execution of its growth strategy through its drilling program. The Company did not receive anyof the proceeds from the sale of the 9,600,000 shares by the selling stockholders. Immediately after the initial public offering and exercise of the over-allotment option granted to the underwriters, First Reserve Midstates Interholding LP and its affiliates owned approximately 41.4% of the Company'soutstanding common stock. On October 1, 2012, the Company closed on the acquisition of all of Eagle Energy Production, LLC's producing properties as well as itsdeveloped and undeveloped acreage primarily in the Mississippian Lime liquids play in Oklahoma and Kansas for $325 million in cash and 325,000shares of the Company's Series A Preferred Stock with an initial liquidation preference value of $1,000 per share (the "Eagle Property Acquisition").The Company funded the cash portion of the Eagle Property Acquisition purchase price with a portion of the net proceeds from the private placement ofF-7Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)1. Organization and Business (Continued)$600 million in aggregate principal amount of 10.75% senior unsecured notes due 2020, which also closed on October 1, 2012 ("2020 Senior Notes"). On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas andOklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (the "Anadarko Basin Acquisition"), beforecustomary post-closing adjustments. The Company funded the purchase price with a portion of the net proceeds from the private placement of$700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021, which also closed on May 31, 2013 ("2021 Senior Notes"). Subsequent to the closing of the Eagle Property Acquisition and the Anadarko Basin Acquisition, the Company has oil and gas operations andproperties in Louisiana, Oklahoma, Texas and Kansas. At December 31, 2013, the Company operated oil and natural gas properties as one reportablesegment engaged in the exploration, development and production of oil, natural gas liquids and natural gas. The Company's management evaluatedperformance based on one reportable segment as there were not significantly different economic or operational environments within its oil and naturalgas properties. All pro forma and per share information presented in the accompanying consolidated financial statements have been adjusted to reflect the effectsof the Company's initial public offering.2. Summary of Significant Accounting PoliciesBasis of Presentation The accompanying consolidated financial statements of the Company have been prepared pursuant to the rules and regulations of the Securities andExchange Commission ("SEC") and have been prepared in accordance with generally accepted accounting principles in the United States of America("GAAP"). All intercompany transactions have been eliminated in consolidation. The consolidated financial statements as of and for the year endedDecember 31, 2013 include the results from the Anadarko Basin Acquisition beginning May 31, 2013. The consolidated financial statements as of andfor the year ended December 31, 2012 include the results from the Eagle Property Acquisition beginning October 1, 2012.Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reportedamounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts ofrevenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, the amount of recoverable oil and natural gas reserves; future cash flows from oil and naturalgas properties; the fair value of commodity derivative contracts; the fair value of share-based compensation; and the valuation of future asset retirementobligations.F-8Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)2. Summary of Significant Accounting Policies (Continued)Cash and Cash Equivalents The Company considers all short-term investments with an original maturity of three months or less to be cash equivalents.Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are stated at the historical carrying amount net of allowance for uncollectible accounts. The carrying amount of the Company'saccounts receivable approximate fair value because of the short-term nature of the instruments. The Company accrues a reserve on a receivable when,based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated.As of December 31, 2013 and 2012, the Company had no allowance for doubtful accounts.Financial Instruments The Company's financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivative contracts.Commodity derivative contracts are recorded at fair value (see Note 3). Based upon recent amendments to the Company's Credit Facility, the Companybelieves the carrying amount of the related floating-rate debt approximates fair value due to the variable nature of the interest rate and the currentfinancing terms available to the Company. The carrying amount of the Company's other financial instruments approximate fair value because of theshort-term nature of the items or variable pricing. See fair value discussion of Senior Notes and Series A Preferred Shares issued in October 2012 inNotes 8 and 10, respectively. Derivative financial instruments are recorded in the consolidated balance sheets as either an asset or liability measured at estimated fair value.Changes in the derivative's fair value are recognized currently in earnings as gains and losses in the period of change. The gains or losses are recordedin "Losses on commodity derivative contracts—net." The related cash flow impact is reflected within cash flows from operating activities.Other Noncurrent Assets At December 31, 2013, other noncurrent assets consisted of $44.7 million in deferred financing costs, $9.7 million in field inventory, and$0.2 million in other noncurrent assets. At December 31, 2012, other noncurrent assets consisted of $25.2 million in deferred financing costs and$0.2 million in other noncurrent assets. The increase in deferred financing costs is the result of approximately $19.3 million in deferred financing costsincurred during 2013 with the issuance of the 2021 Senior Notes.Property and EquipmentOil and Gas Properties The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost ofboth successful and unsuccessful exploration and development activities are capitalized as property and equipment. This includes any internal costs thatare directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similaractivities. Proceeds from the sale orF-9Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)2. Summary of Significant Accounting Policies (Continued)disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company's reserve quantitiesare sold that results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss isgenerally recognized in income.Unevaluated Property Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs representinvestments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impairedor until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization.All unproved property costs are reviewed at least annually to determine if impairment has occurred.Oil and Gas Reserves Proved oil, NGLs and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with therules established by the SEC and the Financial Accounting Standards Board (FASB), which require that reserve estimates be prepared under existingeconomic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractualarrangements. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. TheCompany depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject toamortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserveestimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil andnatural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce perunit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.Impairment of Oil and Gas Properties/Ceiling Test The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties.The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferredincome taxes, may not exceed this "ceiling." The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from theprojected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on thebalance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over thepreceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved andunevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in thecosts being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanyingconsolidated statements of operations. For the year ended December 31, 2013,F-10Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)2. Summary of Significant Accounting Policies (Continued)capitalized costs exceeded the ceiling and an impairment of oil and gas properties of $319.6 million, after tax, was recorded. The most significant factors affecting the impairment related to the transfer of unevaluated property costs to the full cost pool during 2013 andnegative reserve revisions in our Gulf Coast area. During 2013, we transferred $61.2 million of Gulf Coast unevaluated property costs to the full costpool based upon our lack of future plans for further evaluation or development of those leases, and $168.4 million of Mississippian unevaluatedproperty costs attributable to leases that expired during 2013 or that we currently intend to allow to expire in 2014. The negative reserve revisions in ourGulf Coast area were mainly attributable to variability in well performance, our decision during the second quarter to halt further development in ourWest Gordon field and unfavorable cost revisions. See Note 5.Depreciation, Depletion, and Amortization (DD&A) DD&A of oil and gas properties is calculated using the Units of Production Method (UOP). The UOP calculation, in its simplest terms, multipliesthe percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservesare estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated DD&A,estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oiland gas property, less related salvage value.Capitalized Interest Interest from external borrowings is capitalized on unevaluated properties using the weighted-average cost of outstanding borrowings until theproject is substantially complete and ready for its intended use, which for oil and gas assets is at the first production from the field. Capitalized interest isdepleted over the useful lives of the assets in the same manner as the depletion of the underlying assets. The Company paid cash interest of$104.3 million, $7.2 million, and $4.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.Other Property and Equipment Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost.Depreciation is provided principally using the straight-line method over the estimated useful lives of the assets, which primarily range from three toseven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.Accrued Liabilities Accrued liabilities at December 31, 2013 consisted of $87.2 million in oil and gas capital expenditures, $64.4 million in accrued revenue androyalty distributions, $21.3 million in accrued interest, $8.3 million in accrued lease operating and workover expenses, $4.4 million in accrued taxes,and $18.8 million in other accrued liabilities. At December 31, 2012, the balance consisted of $69.0 million in oil and gas capital expenditures,$16.2 million in accrued interest, and $13.4 million in other accrued liabilities.F-11Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)2. Summary of Significant Accounting Policies (Continued)Asset Retirement Obligations The legal obligations associated with the retirement of long-lived assets are recognized at estimated fair value at the time that the obligation isincurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. The Company estimates the fair value of an assetretirement obligation in the period in which the obligation is incurred and can be reliably measured. The corresponding asset retirement cost iscapitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and thecapitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, anyadjustment is recorded in the full cost pool. See Note 7.Share-Based Compensation We measure share-based compensation cost at fair value and generally recognize the corresponding compensation expense on a straight-line basisover the service period during which awards are expected to vest. We include share-based compensation expense, net of amounts capitalized to oil andgas properties, in "General and administrative expense" in our consolidated statements of operations. See Note 10.Revenue Recognition Oil, NGLs and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery hasoccurred and title has transferred and collection of the revenues is reasonably assured. Cash received relating to future revenues is deferred andrecognized when all revenue recognition criteria are met. The Company follows the sales method of accounting for oil and gas revenues, whereby revenue is recognized for all oil and gas sold topurchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognizedas a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil and gas reserves. The Company hadno significant imbalances at December 31, 2013 or 2012.Acquisition and Transaction Costs Acquisition related costs are expensed as incurred and as services are received. Such costs include finders' fees; advisory, legal, accounting,valuation and other professional and consulting fees; and acquisition related general and administrative costs. Costs incurred in 2013 relate to theAnadarko Basin Acquisition and costs incurred in 2012 relate to the Eagle Property Acquisition. See Note 6.Income Taxes Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferredincome taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred incometax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets arerecovered or liabilities are settled. DeferredF-12Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)2. Summary of Significant Accounting Policies (Continued)income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured byapplying currently enacted tax rates. The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meetthe more-than-likely-than-not recognition threshold are recognized. Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or stateincome tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as theCompany's equity holders were responsible for income tax on the Company's profits. In connection with the closing of the Company's initial publicoffering, the Company merged into a corporation and became subject to federal and state income taxes. The Company's book and tax basis in assets andliabilities differed at the time of the corporate reorganization due primarily to different cost recovery periods utilized for book and tax purposes for theCompany's oil and natural gas properties. See Note 11.Earnings (Loss) Per Share Basic earnings (loss) per common share is calculated by dividing net income available to common shareholders by the weighted average number ofcommon shares outstanding during each period. Diluted earnings (loss) per common share is calculated by dividing net income available to commonshareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities.Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options (ifany) using the treasury method, as well as the Company's Series A Preferred Stock using the if-converted method. In the computation of dilutedearnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stockoptions (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that suchexcess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.Recent Accounting Pronouncements The Company reviewed recently issued accounting pronouncements that became effective during the twelve months ended December 31, 2013,and determined that none would have a material impact on the Company's consolidated financial statements with the exception of the adoption ofASU 2011-11, "Disclosures About Offsetting Assets and Liabilities", which the Company adopted on January 1, 2013 and that applies to thedisclosures regarding commodity derivative contracts discussed in Note 4.Correction of the 2012 Net Deferred Tax Liability In the third quarter of 2013, the Company determined that its 2012 accounting for the tax impacts of the merger of certain entities that occurred inconnection with the Company's initial public offering was in error. The Company identified that certain tax attributes acquired from the merged entitieswere not properly identified. Because the tax attributes were acquired as a result of a merger of entities under common control, the impacts of these taxattributes should have been recorded through equity at the time the Company became a taxable entity.F-13Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)2. Summary of Significant Accounting Policies (Continued) To correct the 2012 tax error, the Company has restated the accompanying Consolidated Balance Sheet and the Consolidated Statement of Changesin Stockholders'/Members Equity as of December 31, 2012. There was no impact to the Consolidated Statements of Operations or the ConsolidatedStatement of Cash Flows for the year ended December 31, 2012. The impact of the correction is shown in the table below (in thousands):3. Fair Value Measurements of Financial Instruments The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified intotwo categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas,unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue costand effort. These two types of inputs are further divided into the following fair value input hierarchy:•Level 1—Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. •Level 2—Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly.Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable forthe asset or liability. Fair value assets and liabilities that are generally included in this category are commodity derivative contracts withfair values based on inputs from actively quoted markets. The Company uses a discounted cash flow approach to estimate the fair valuesof its commodity derivative contracts, utilizing commodity futures price strips for the underlying commodities provided by a reputablethird-party. •Level 3—Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the assetor liability. Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company's assessmentof the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets andliabilities and their placement within the fair value hierarchy levels.Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative Instruments—Commodity derivative contracts reflected in the consolidated balance sheets are recorded at estimated fair value. AtDecember 31, 2013 and 2012, all of the Company's commodityF-14 December 31, 2012 Balance Sheet As PreviouslyReported As Restated Deferred income taxes $190,625 $156,737 Total long-term liabilities 905,002 871,114 Additional paid-in-capital 830,003 863,891 Total stockholders' equity 643,581 677,469 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)3. Fair Value Measurements of Financial Instruments (Continued)derivative contracts were with seven and five bank counterparties, respectively, and are classified as Level 2. Fair Value Measurements at December 31, 2013 Quoted Pricesin ActiveMarkets(Level 1) SignificantOtherObservableInputs(Level 2) SignificantUnobservableInputs(Level 3) Total (in thousands) Assets: Commodity derivative NGL swaps $— $469 $— $469 Commodity derivative gas swaps — 488 — 488 Commodity derivative oil collars — 64 — 64 Commodity derivative gas collars — 751 — 751 Commodity derivative differential swaps — 806 — 806 Total assets $— $2,578 $— $2,578 Liabilities: Commodity derivative oil swaps $— $32,209 $— $32,209 Commodity derivative NGL swaps — 74 — 74 Commodity derivative gas swaps — 809 — 809 Commodity derivative oil collars — 272 — 272 Commodity derivative gas collars — 26 — 26 Total liabilities $— $33,390 $— $33,390 Fair Value Measurements at December 31, 2012 Quoted Pricesin ActiveMarkets(Level 1) SignificantOtherObservableInputs(Level 2) SignificantUnobservableInputs(Level 3) Total (in thousands) Assets: Commodity derivative oil swaps $— $16,133 $— $16,133 Commodity derivative NGL swaps — 2,353 — 2,353 Commodity derivative oil collars — 428 — 428 Commodity derivative gas collars — 2,026 — 2,026 Commodity derivative differential swaps — 2,661 — 2,661 Total assets $— $23,601 $— $23,601 Liabilities: Commodity derivative oil swaps $— $15,091 $— $15,091 Commodity derivative NGL swaps — 458 — 458 Commodity derivative oil collars — 287 — 287 Commodity derivative gas collars — 185 — 185 Commodity derivative differential swaps — 11,693 — 11,693 F-15Commodity derivative differential swaps — 11,693 — 11,693 Total liabilities $— $27,714 $— $27,714 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)3. Fair Value Measurements of Financial Instruments (Continued) Derivative instruments listed above are presented gross and include collars and swaps that are carried at fair value. The Company records the netchange in the fair value of these positions in "Losses on commodity derivative contracts—net" in the Company's consolidated statements of operations.See Note 4 for additional information on the Company's derivative instruments and balance sheet presentation.4. Risk Management and Derivative Instruments The Company is exposed to fluctuations in crude oil, NGLs and natural gas prices. The Company believes it is prudent to manage the variability incash flows by entering into derivative financial instruments to economically hedge a portion of its crude oil, NGLs and natural gas production. TheCompany utilizes various types of derivative financial instruments, including swaps, collars and options, to manage fluctuations in cash flows resultingfrom changes in commodity prices. These derivative contracts are placed with major financial institutions that the Company believes are minimal creditrisks. The oil, NGLs and gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that managementbelieves have a high degree of historical correlation with actual prices received by the Company for its oil, NGLs and natural gas production. Inherent in the Company's portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market riskis the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the riskof loss from nonperformance by the Company's counterparty to a contract. The Company does not require collateral from its counterparties but doesattempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are largefinancial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company hasentered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability positionin the event of default by the counterparty. Due to the netting arrangements, had the Company's counterparties failed to perform under existingcommodity derivative contracts, the maximum loss at December 31, 2013 would have been approximately $0.7 million.F-16Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)4. Risk Management and Derivative Instruments (Continued)Commodity Derivative Contracts As of December 31, 2013, the Company had the following open commodity positions:Balance Sheet Presentation The following table summarizes the gross fair value of derivative instruments by the appropriate balance sheet classification, even when thederivative instruments are subject to netting arrangementsF-17 HedgedVolume Weighted-AverageFixed PriceOil (Bbls): WTI Swaps—2014 4,344,450 $88.76WTI Swaps—2015 1,820,000 $86.55WTI Collars—2014 164,400 $88.49 - $97.94WTI to LLS Basis Differential Swaps—2014(1) 501,000 $5.35NGL (Bbls): NGL Swaps—2014 151,500 $62.16Natural Gas (MMBtu): Swaps—2014(2) 17,885,000 $4.17Swaps—2015 18,250,000 $4.13Collars—2014(3) 1,685,004 $3.99 - $5.09(1)The Company enters into swap arrangements intended to fix the positive differential between the Louisiana Light Sweet("LLS") pricing and West Texas Intermediate ("NYMEX WTI") pricing. (2)Includes 1,519,000 MMBtu that priced in the fourth quarter of 2013, but had not cash settled as of December 31, 2013. (3)Includes 64,667 MMBtu that priced in the fourth quarter of 2013, but had not cash settled as of December 31, 2013.Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)4. Risk Management and Derivative Instruments (Continued)and qualify for net presentation in the Company's consolidated balance sheets at December, 2013 and 2012, respectively (in thousands):Type Balance Sheet Location(1) December 31,2013 December 31,2012 Oil Swaps Derivative financialinstruments—CurrentAssets $— $16,004 Oil Swaps Derivative financialinstruments—Non-Current Assets — 129 Oil Swaps Derivative financialinstruments—CurrentLiabilities (28,871) (11,485)Oil Swaps Derivative financialinstruments—Non-Current Liabilities (3,338) (3,606)NGL Swaps Derivative financialinstruments—CurrentAssets 469 1,624 NGL Swaps Derivative financialinstruments—Non-Current Assets — 729 NGL Swaps Derivative financialinstruments—CurrentLiabilities (74) (336)NGL Swaps Derivative financialinstruments—Non-Current Liabilities — (122)Gas Swaps Derivative financialinstruments—CurrentAssets 469 — Gas Swaps Derivative financialinstruments—Non-Current Assets 19 — Gas Swaps Derivative financialinstruments—CurrentLiabilities (496) — Gas Swaps Derivative financialinstruments—Non-Current Liabilities (313) — Oil Collars Derivative financialinstruments—CurrentAssets 64 221 Oil Collars Derivative financialinstruments—Non-Current Assets — 207 Derivative financialinstruments—CurrentOil Collars Liabilities (272) (238)Oil Collars Derivative financialinstruments—Non-Current Liabilities — (49)Gas Collars Derivative financialinstruments—CurrentAssets 751 1,129 Gas Collars Derivative financialinstruments—Non-Current Assets — 897 Gas Collars Derivative financialinstruments—CurrentLiabilities (26) (112)Gas Collars Derivative financialinstruments—Non-Current Liabilities — (73)Basis DifferentialSwaps Derivative financialinstruments—CurrentAssets 806 2,625 Basis DifferentialSwaps Derivative financialinstruments—Non-Current Assets — 36 Basis DifferentialSwaps Derivative financialinstruments—CurrentLiabilities — (11,319)Basis DifferentialSwaps Derivative financialinstruments—Non-Current Liabilities — (374) Total derivativefair value atperiod end $(30,812)$(4,113) (1)The fair values of commodity derivative instruments reported in the Company's consolidated balance sheets are subject to nettingarrangements and qualify for net presentation. The following table summarizes the location and fair value amounts of allderivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amountsoffset in the consolidated balance sheets at December 31, 2013 and 2012, respectively (in thousands): December 31, 2013 Not Designated asASC 815 Hedges: Balance Sheet Classification GrossRecognizedAssets/Liabilities GrossAmountsOffset NetRecognizedFair ValueAssets/Liabilities Derivativeassets: Commoditycontracts Derivative financialinstruments—current $2,559 $1,859 $700 Commoditycontracts Derivative financialinstruments—noncurrent 19 — 19 $2,578 $1,859 $719 Derivativeliabilities: CommodityDerivative financialF-18contracts instruments—current $29,739 $1,859 $27,880 Commoditycontracts Derivative financialinstruments—noncurrent 3,651 — 3,651 $33,390 $1,859 $31,531 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)4. Risk Management and Derivative Instruments (Continued) Gains/Losses on Commodity Derivative Contracts The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly,commodity derivative contracts are marked-to-market each quarter with the change in fair value during the periodic reporting period recognized currentlyas a gain or loss in "Losses on commodity derivative contracts—net" within revenues in the audited consolidated statements of operations. Realizedgains and losses represent the actual settlements under commodity derivative contracts that require making a payment to or receiving a payment from thecounterparty, as well as any deferred premiums payable to the counterparty upon contract settlement. During the year ended December 31, 2012, theCompany paid deferred premiums of $3.3 million related to put options covering a total of 549,000 barrels of crude oil, respectively. No such paymentsfor deferred premiums were made during 2013. The following table presents realized net losses and unrealized net (losses) gains recorded by the Company in "Losses on commodity derivativecontracts—net" related to the change in fair value of the commodity derivative instruments for the periods presented:F-19 December 31, 2012 Not Designated asASC 815 Hedges: Balance Sheet Classification GrossRecognizedAssets/Liabilities GrossAmountsOffset NetRecognizedFair ValueAssets/Liabilities Derivativeassets: Commoditycontracts Derivative financialinstruments—current $21,603 $15,908 $5,695 Commoditycontracts Derivative financialinstruments—noncurrent 1,998 281 1,717 $23,601 $16,189 $7,412 Derivativeliabilities: Commoditycontracts Derivative financialinstruments—current $23,490 $15,908 $7,582 Commoditycontracts Derivative financialinstruments—noncurrent 4,224 281 3,943 $27,714 $16,189 $11,525 For the Year Ended December 31, 2013 2012 2011 (in thousands) Realized net losses $(17,585)$(15,825)$(16,733)Unrealized net (losses) gains (26,699) 4,667 11,889 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)5. Property and Equipment The Company's property and equipment as of December 31, 2013 and 2012 was as follows (in thousands): For the years ended December 31, 2013, 2012 and 2011, depletion expense related to oil and gas properties was $248.2 million, $125.1 millionand $91.4 million, respectively and $28.42, $34.17 and $33.40 per barrel of oil equivalent ("Boe"), respectively. For the years ended December 31,2013, 2012 and 2011, depreciation expense related to other property and equipment was $2.2 million, $0.5 million and $0.3 million, respectively. For the years ended December 31, 2013, 2012 and 2011, interest capitalized to unevaluated properties was $32.2 million, $11.2 million and$2.6 million, respectively. For the years ended December 31, 2013 and 2012, the Company capitalized $8.4 million and $1.5 million, respectively, ofinternal costs to oil and gas properties, including $1.4 million and $0.2 million, respectively, of qualifying share based compensation expense (seeNote 10).6. Acquisition of Oil and Gas PropertiesAnadarko Basin Acquisition—May 2013 On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas andOklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (before customary post-closing adjustments).The Company funded the purchase price of the Anadarko Basin Acquisition with a portion of the net proceeds from the private placement of$700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021, which also closed on May 31, 2013.F-20 December 31,2013 December 31,2012 (in thousands) Oil and gas properties, on the basis of full-cost accounting: Proved properties $2,817,062 $1,522,723 Unevaluated properties 243,599 313,941 Other property and equipment 11,113 5,038 Less accumulated depreciation, depletion, amortization and impairment (976,880) (274,294) Net property and equipment $2,094,894 $1,567,408 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)6. Acquisition of Oil and Gas Properties (Continued) The transaction was accounted for using the acquisition method of accounting which requires, among other things, that assets acquired andliabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value for certain assets and liabilitiesremains preliminary and will be completed after post-closing purchase price adjustments are finalized no later than one year from the acquisition date. The following table summarizes (in thousands) the preliminary estimate of the assets acquired and liabilities assumed in the acquisition. The finaldetermination of the certain assets and liabilities will be completed as soon as the post-closing purchase price adjustments are finalized. These amountswill be finalized as soon as practicable, but no later than one year from the acquisition date. The fair values of oil and natural gas properties and asset requirement obligations were measured using valuation techniques that convert futurecash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) oil and gasreserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) market based weightedaverage cost of capital. Significant inputs to the valuation of asset retirement obligations include estimates of: (i) the timing of future plugging andabandonment activities; (ii) future plugging and abandonment costs; and (iii) market based weighted average cost of capital. These inputs requiresignificant judgments and estimates by the Company's management at the time of the valuation and are the most sensitive and subject to change.Eagle Property Acquisition—October 2012 On October 1, 2012, the Company closed on the Eagle Property Acquisition. The assets acquired include certain interests in producing oil andnatural gas assets and unevaluated leasehold acreage in Oklahoma and Kansas and related hedging instruments. The aggregate purchase price, beforeadjustments for expenses incurred and revenue received by Eagle from June 1, 2012 through the closing date and other customary post-closingpurchase price adjustments, consisted of (a) $325 million in cash and (b) 325,000 shares of Series A Preferred Stock with an initial liquidationpreference of $1,000/share. The Company funded the cash portion of the Eagle Property Acquisition purchase price with a portion of the net proceedsfrom the private placement (which also closed on October 1, 2012) of $600 million in aggregate principal amount of 10.75% senior unsecured notes dueOctober 1, 2020.F-21 Anadarko BasinAcquisition Oil and gas properties Proved $418,287 Unevaluated 207,789 Total assets acquired $626,076 Asset retirement obligations 6,296 Total liabilities assumed $6,296 Net assets acquired $619,780 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)6. Acquisition of Oil and Gas Properties (Continued) The transaction was accounted for using the acquisition method of accounting . The fair value of, and the allocation to, the assets acquired andliabilities assumed in the Eagle Property Acquisition has been finalized and is shown in the following table (in thousands): The finalized balances in the table above include immaterial changes to the amounts originally allocated to oil and gas properties and deferredincome tax liabilities. These changes were required to reflect the final consideration paid after adjustments for certain post-closing purchase priceamounts.Other Property Acquisitions On April 1, 2013, the Company exercised preference rights and acquired additional acreage and producing wells in its Gulf Coast region for$3.4 million.Actual and Pro Forma Impact of Acquisitions—unaudited Revenues attributable to the Anadarko Basin Acquisition included in the Company's consolidated statements of operations for the year endedDecember 31, 2013 were $104.7 million. Revenues attributable to the Eagle Property Acquisition, included in the Company's consolidated statements ofoperations for the year ended December 31, 2012 were $28.4 million.F-22 Eagle PropertyAcquisition Oil and gas properties: Proved $419,549 Unevaluated 244,236 Commodity derivative contracts 8,453 Total assets acquired $672,238 Asset retirement obligations 2,662 Deferred income tax liabilities 25,985 Commodity derivative contracts — Total liabilities assumed $28,647 Net assets acquired $643,591 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)6. Acquisition of Oil and Gas Properties (Continued) The following table presents unaudited pro forma information for the Company as if the Eagle Property Acquisition occurred on January 1, 2011and the Anadarko Basin Acquisition occurred on January 1, 2012: The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Eagle PropertyAcquisition and the Anadarko Basin Acquisition and are factually supportable. The unaudited pro forma consolidated results are not necessarilyindicative of what the Company's consolidated results of operations actually would have been had the Eagle Property Acquisition been completed onJanuary 1, 2011 and if the Anadarko Basin Acquisition had been completed on January 1, 2012. In addition, the unaudited pro forma consolidatedresults do not purport to project the future results of operations for the combined Company.Acquisition and Transaction Expenses For the year ended December 31, 2013, acquisition and transaction costs are costs the Company has incurred as a result of the Anadarko BasinAcquisition and include advisory, legal, accounting, valuation and other professional and consulting fees; and general and administrative costs. For theyear ended December 31, 2013, the Company recorded $11.8 million of such expenses. For the year ended December 31, 2012, acquisition and transaction costs are costs the Company has incurred as a result of the Eagle PropertyAcquisition and include finders' fees; advisory, legal, accounting, valuation and other professional and consulting fees; and acquisition related generaland administrative costs. For the year ended December 31, 2012, the Company recorded $14.9 million of such expenses.7. Asset Retirement Obligations For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, such as wells, service assets and otherfacilities. The fair value of the asset retirement obligation at inception is capitalized as part of the carrying amount of the related long-lived assets. Assetretirement obligations approximated $26.3 million and $15.2 million as of December 31, 2013 and 2012,F-23 For the Year Ended December 31, 2013(1) 2012(2) 2011(3) Revenues and other $539,562 $490,241 $287,119 Net income (loss) (340,400) (129,885) 21,066 Preferred stock dividends (15,589) (26,000) (26,000) Net loss attributable to common shareholders $(355,989)$(155,885)$(4,934)Net loss per common share—basic and diluted $(5.41)$(2.60) N/A (1)Includes the effect of the Anadarko Basin Acquisition, as the Eagle Property Acquisition was included in the historicalresults for this period. (2)Includes the effect of the Eagle Property Acquisition and the Anadarko Basin Acquisition. (3)Includes the effect of the Eagle Property Acquisition.Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)7. Asset Retirement Obligations (Continued)respectively. The liability has been accreted to its present value as of December 31, 2013 and 2012. The Company evaluated its wells and determined arange of abandonment dates through 2071. At December 31, 2013, all asset retirement obligations represent long-term liabilities and are classified assuch. The following table details the change in the asset retirement obligations for the years ended December 31, 2013, 2012 and 2011, respectively (inthousands): Revisions during the year ended December 31, 2013 were due to an increase in estimated future abandonment costs based upon higher oilfieldservice pricing. Revisions during the year ended December 31, 2012 were due to an increase in estimated future abandonment costs for our Gulf Coastwells based upon higher oilfield service pricing and a change in the Company's approach to site remediation based upon expected environmental andregulatory requirements.8. Long-Term Debt The Company's long-term debt as of December 31, 2013 and 2012 is as follows:Reserve-based Credit Facility As of December 31, 2013, the Company's credit facility consisted of a $750 million senior revolving credit facility (the "Credit Facility") with aborrowing base of $500 million, as recently redetermined on September 26, 2013, when the borrowing base was increased from $425 million. AtDecember 31, 2013, outstanding letters of credit obligations total $0.2 million. The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of the Company's oil and natural gasproperties and currently bear interest at LIBORF-24 Year ended December 31, 2013 2012 2011 Asset retirement obligations at beginning of year $15,245 $7,627 $2,859 Liabilities incurred 2,535 3,044 1,294 Liabilities assumed in Anadarko Basin Acquisition 6,296 — — Liablities assumed in Eagle Property Acquisition — 2,662 — Revisions 858 1,189 3,196 Liabilities settled (61) — (56)Current period accretion expense 1,435 723 334 Asset retirement obligations at end of year $26,308 $15,245 $7,627 At December 31, 2013 2012 (in thousands) Revolving credit facility, due 2018 $401,150 $94,000 Senior notes, due 2020 600,000 600,000 Senior notes, due 2021 700,000 — Long-term debt $1,701,150 $694,000 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)8. Long-Term Debt (Continued)plus an applicable margin, depending upon the Company's borrowing base utilization, between 1.75% and 2.75% per annum. At December 31, 2013and December 31, 2012, the weighted average interest rate was 2.5% and 2.5%, respectively. In addition to interest expense, the Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at therate of either 0.375% or 0.50% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings duringeach quarter. The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October and up to one additional time per sixmonth period following each scheduled borrowing base redetermination, as may be requested by the Company or the administrative agent, acting onbehalf of lenders holding at least two-thirds of the outstanding loans and other obligations. The next scheduled borrowing base redetermination date isOctober 1, 2014, assuming the financing discussed in Note 15 closes as planned. Under the terms of the Credit Facility, the Company is required to repay the amount by which the principal balance of its outstanding loans and itsletter of credit obligations exceed its redetermined borrowing base. The Company is permitted to make such repayment in six equal successive monthlypayments commencing 30 days following the administrative agent's notice regarding such borrowing base reduction. On September 26, 2013, the Company entered into the Assignment and Fourth Amendment to the Second Amended and Restated CreditAgreement among the Company, as parent, Midstates Sub, as borrower, SunTrust Bank as administrative agent, and the other lenders and parties partythereto (the "Fourth Amendment"). The Fourth Amendment amended the Credit Facility to provide that the Company's ratio of total net indebtedness to EBITDA for the trailing fourfiscal quarter period ending on the last day of such fiscal quarter cannot exceed (i) 4.75:1.0, for the fiscal quarters ending December 31, 2013 andMarch 31, 2014, (ii) 4.50:1.0, for the fiscal quarters ending June 30, 2014, (iii) 4.25:1.0, for the fiscal quarters ending September 30, 2014 andDecember 31, 2014, and (iv) 4.00:1.0, for the fiscal quarter ending March 31, 2015 and each fiscal quarter thereafter. The Company also agreed to pay aone-time fee of 0.50% to each lender on the portion of their commitment to the borrowing base under the Fourth Amendment in excess of theircommitment prior to the Fourth Amendment, and a one-time fee of 0.10% to each lender on the lesser of such lenders commitment immediately prior to,or after giving effect to, the Fourth Amendment. The Credit Facility contains financial covenants, in addition to the maximum ratio of debt to EBITDA discussed above, which, among other things,set a minimum current ratio (as defined therein) of not less than 1.0 to 1.0 and various other standard affirmative and negative covenants including, butnot limited to, restrictions on the Company's ability to make any dividends, distributions or redemptions. As of December 31, 2013, the Company was in compliance with the minimum current ratio and the ratio of debt to EBITDA covenants as set forthin the Credit Facility. The Company's current ratio at December 31, 2013 was 1.3 to 1.0. At December 31, 2013, the Company's ratio of debt toEBITDA was 4.4 to 1.0.F-25Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)8. Long-Term Debt (Continued) Based upon the recent amendments to the Credit Facility, the Company believes its carrying amount at December 31, 2013 approximates its fairvalue (Level 2) due to the variable nature of the applicable interest rate and current financing terms available to the Company.2020 Senior Notes On October 1, 2012, the Company issued $600 million in aggregate principal amount of 10.75% senior notes due 2020 (the "2020 OutstandingNotes") in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the "Securities Act").On October 29, 2013, substantially all of the 2020 Outstanding Notes were exchanged for an equal principal amount of registered 10.75% seniorsubordinated notes due 2020 pursuant to an effective registration statement on Form S-4 filed on August 30, 2013 under the Securities Act (the "2020Exchange Notes"). The 2020 Exchange Notes are identical to the 2020 Outstanding Notes except that the 2020 Exchange Notes are registered under theSecurities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. As used in this Form 10-K, the term"2020 Senior Notes" refers to both the 2020 Outstanding Notes and the 2020 Exchange Notes. The 2020 Senior Notes were co-issued on a joint andseveral basis by the Company and its wholly owned subsidiary, Midstates Sub. The Company does not have any operations or independent assets otherthan its 100% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The 2020 Senior Notes Indenture does notcreate any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends ormake loans to the Company or limit the ability of the Company to advance loans to Midstates Sub. At any time prior to October 1, 2015, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the2020 Senior Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the 2020Senior Notes, plus any accrued and unpaid interest up to the redemption date. In addition, at any time before October 1, 2016, the Company may redeemall or a part of the 2020 Senior Notes at a redemption price equal to 100% of the principal amount of 2020 Senior Notes redeemed plus the ApplicablePremium (as defined in the Indenture) at the redemption date, plus any accrued and unpaid interest and Additional Interest (as defined in the Indenture),if any, up to, the redemption date. On or after October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at varying redemptionprices (expressed as percentages of principal amount) set forth in the Indenture plus accrued and unpaid interest and Additional Interest (as defined inthe Indenture), if any, on the 2020 Senior Notes redeemed, up to, the redemption date. The Indenture contains covenants that, among other things, restrict the Company's ability to: (i) incur additional indebtedness, guaranteeindebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make otherdistributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certainassets; (vi) enter into certain types of transactions with the Company's affiliates; (vii) consolidate, merge or sell substantially all of the Company's assets;(viii) prepay, redeem or repurchase certain debt; (ix) alter the business the Company conducts and (x) enter into agreements restricting the ability of theCompany's current and any future subsidiaries to pay dividends. Upon the occurrence of certain change of control events, as defined in the Indenture, each holder of the 2020 Senior Notes will have the right torequire that the Company repurchase all or a portion ofF-26Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)8. Long-Term Debt (Continued)such holder's 2020 Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaidinterest to the date of repurchase. The estimated fair value of the 2020 Senior Notes was $648.0 million as of December 31, 2013 (Level 2 in the fair value measurement hierarchybased on the limited trading volume on the secondary market), based on quoted market prices for these same debt securities. The effective annualinterest rate for the 2020 Senior Notes was approximately 11.1% for the years ended December 31, 2013 and 2012.2021 Senior Notes On May 31, 2013, the Company issued $700 million in aggregate principal amount of 9.25% senior notes due 2021 (the "2021 OutstandingNotes") in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act. On October 29, 2013, all of the 2021Outstanding Notes were exchanged for an equal principal amount of registered 9.25% senior subordinated notes due 2021 pursuant to an effectiveregistration statement on Form S-4 filed on August 30, 2013 under the Securities Act (the "2021 Exchange Notes"). The 2021 Exchange Notes areidentical to the 2021 Outstanding Notes except that the 2021 Exchange Notes are registered under the Securities Act and do not have restrictions ontransfer, registration rights or provisions for additional interest. As used in this Form 10-K, the term "2021 Senior Notes" refers to both the 2021Outstanding Notes and the 2021 Exchange Notes. The proceeds from the offering of $700 million (net of the initial purchasers' discount and relatedoffering expenses) were used to fund the Anadarko Basin Acquisition and the related expenses, to pay the expenses related to an amendment to theCompany's revolving credit facility, to repay $34.3 million in outstanding borrowings under the Company's Credit Facility, and for general corporatepurposes. The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes. The 2021 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. TheCompany does not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no othersubsidiaries of the Company. The 2021 Senior Notes indenture does not create any restricted assets within Midstates Sub, nor does it impose anysignificant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advanceloans to Midstates Sub. On or prior to May 31, 2014, the Company may redeem up to $100.0 million of aggregate principal amount of the 2021 Senior Notes with the netcash proceeds from any Equity Offerings (as such term is defined in the 2021 Senior Notes Indenture) at a redemption price equal to 103% of theprincipal amount plus accrued and unpaid interest. Prior to June 1, 2016, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2021 SeniorNotes (less the amount of 2021 Senior Notes redeemed pursuant to the preceding paragraph) with the net proceeds of any Equity Offerings at aredemption price of 109.25% of the principal amount of the 2021 Senior Notes redeemed, plus any accrued and unpaid interest, if any, up to theredemption date. In addition, at any time before June 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at a redemption priceequal to 100% of the principal amount of the 2021 Senior Notes redeemed plus the Applicable Premium (as defined in the Indenture) at the redemptiondate, plus any accrued and unpaid interest and Additional InterestF-27Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)8. Long-Term Debt (Continued)(as defined in the 2021 Senior Notes Indenture), if any, up to, the redemption date. On or after October 1, 2016, the Company may redeem all or a partof the 2021 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2021 Senior Notes Indenture plusaccrued and unpaid interest and Additional Interest (as defined in the 2021 Senior Notes Indenture), if any, on the 2021 Senior Notes redeemed, up to,the redemption date. The terms of the covenants and change in control provisions in the 2021 Senior Notes Indenture are substantially identical to those of the 2020Senior Notes discussed above. The estimated fair value of the 2021 Senior Notes was $724.5 million as of December 31, 2013 (Level 2 in the fair value measurement hierarchybased on the limited trading volume on the secondary market), based on quoted market prices for these same debt securities. The effective annualinterest rate for the 2021 Senior Notes was approximately 9.5% for the year ended December 31, 2013.9. Mandatorily Redeemable Convertible Preferred Units In December 2011, Holdings LLC, FR Midstates Holdings LLC ("FR Midstates") and Midstates Petroleum Holdings, Inc. ("Petroleum Inc.")entered into an amended and restated limited liability company agreement, which was later amended in March 2012, to provide for the issuance of up to65,000, or $65 million in aggregate value, of certain mandatorily redeemable convertible preferred units (the "Preferred Units") between December 15,2011 and June 10, 2015. The Preferred Units had a liquidation value of $1,000 per unit and bore interest, compounded quarterly, at a rate of 8% plusthe greater of LIBOR or 1.5%. The Preferred Units were convertible into units of Holdings LLC on or after the one year anniversary of the date ofissuance into a number of common units with a fair market value (as determined by the Board of Directors) equal to the liquidation value plus anyaccrued interest and were redeemable for cash at any time at the option of Holdings LLC, but were mandatorily redeemable for cash on June 10, 2015,unless otherwise converted. In addition, a fixed interest charge of 1.5% of the aggregate capital invested in the Preferred Units was payable uponredemption or conversion. On January 4, 2012, and again on February 9, 2012, Holdings LLC issued 20,000 Preferred Units (for a total of 40,000 Preferred Units) to FRMidstates for aggregate cash proceeds of $40.0 million. On April 3, 2012, Holdings LLC issued an additional 25,000 preferred units to FR Midstatesfor aggregate cash proceeds of $25.0 million. On April 26, 2012, the Company used $67.1 million of the proceeds from its initial public offering to redeem the Preferred Units in full, includinginterest and other charges. As such, at December 31, 2012, the Preferred Units are no longer outstanding. The Company recorded $2.1 million related tointerest expense associated with these Preferred Units for the year ended December 31, 2012. There was no related interest expense for the year endedDecember 31, 2013.10. Equity and Share-Based CompensationCommon and Preferred Shares At December 31, 2011, Holdings LLC had 256,742 common units issued and outstanding. On April 24, 2012, in connection with the Company'sinitial public offering, a corporate reorganization occurred and each common unit of Holdings LLC was converted into approximately 185.5 commonshares of the Company and as a result, the Company issued 47,634,353 shares of its common stock.F-28Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)10. Equity and Share-Based Compensation (Continued) On April 25, 2012, the Company completed its initial public offering of common stock pursuant to a registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Pursuant to the registration statement, the Company registered the offer andsale of 27,600,000 shares of $0.01 par value common stock, which included 6,000,000 shares of stock sold by the selling shareholders and 3,600,000shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments. After the corporate reorganization and the completion of its initial public offering discussed above, the Company is authorized to issue up to a totalof 300,000,000 shares of its common stock with a par value of $0.01 per share, and 50,000,000 shares of its preferred stock with a par value of $0.01per share. Holders of the Company's common shares are entitled to one vote for each share held of record on all matters submitted to a vote ofstockholders and to receive ratably in proportion to the shares of common stock held by them any dividends declared from time to time by the board ofdirectors. The common shares have no preferences or rights of conversion, exchange, pre-exemption or other subscription rights. With respect to preferred shares, the Company is authorized, without further stockholder approval, to establish and issue from time to time one ormore classes or series of preferred stock with such powers, preferences, rights, qualifications, limitations and restrictions as determined by its board ofdirectors.Series A Preferred Stock In connection with the Eagle Property Acquisition, on September 28, 2012, the Company designated 325,000 shares of Series A MandatorilyConvertible Preferred Stock (the "Series A Preferred Stock") with an initial liquidation preference of $1,000 per share and an 8% per annum dividend,payable semiannually at the Company's option in cash or through an increase in the liquidation preference. The Series A Preferred Shares areconvertible after October 1, 2013, in whole but not in part and at the option of the holders of a majority of the outstanding shares of Series A PreferredStock, into a number shares of the Company's common stock calculated by dividing the then-current liquidation preference by the conversion price of$13.50 per share and, if not previously converted, are mandatorily convertible at September 30, 2015 into shares of the Company's common stock at aconversion price no greater than $13.50 per share and no less than $11.00 per share, with the ultimate conversion price dependent upon the volumeweighted average price of the Company's common stock during the 15 trading days immediately prior to September 30, 2015. The Series A PreferredStock was issued on October 1, 2012. On March 30, 2013, the Company elected to pay the $13 million semi-annual dividend due on that date through an increase in the Series APreferred Stock liquidation preference to $1,040. As a result, the Company will be obligated to issue between 962,963 and 1,181,818 additional sharesof common stock upon conversion of the Series A Preferred Stock, with the ultimate number of shares dependent upon the conversion price then ineffect as described above. On September 30, 2013, the Company elected to pay the $13.5 million semi-annual dividend due on that date through an increase in the Series APreferred Stock liquidation preference to $1,082. As a result, the Company will be obligated to issue between 1,001,481 and 1,229,091 additionalshares of common stock upon conversion of the Series A Preferred Stock, with the ultimate number of shares dependent upon the conversion price thenin effect as discussed above.F-29Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)10. Equity and Share-Based Compensation (Continued) For the three months ended December 31, 2013, the $6.3 million Series A Preferred Stock dividend was based upon the estimated fair value of639,127 common shares that would have been issued had the notional dividend amount of $7.0 million been converted into common shares at aconversion price of $11.00 per share. For the twelve months ended December 31, 2013, the $15.6 million Series A Preferred Stock dividend was based upon the estimated fair value of2,459,127 common shares that would have been issued had the notional dividend amounts for the year of $27.1 million been converted into commonshares at a conversion price of $11.00 per share. The following table demonstrates the number of shares to be issued upon conversion through December 31, 2013 at the respective conversionrates based upon the current liquidation preference:Share Activity The following table summarizes changes in the number of outstanding shares since January 1, 2011: At December 31, 2013, the Company had 68,925,745 and 68,807,043 shares of its common stock issued and outstanding, respectively, and325,000 shares of Series A Preferred Stock issued and outstanding.F-30 Conversion at$13.50/share Conversion at$11.00/share Number of Common Shares Issuable Upon Conversion 26,077,807 32,004,582 Number of Shares Series APreferredStock CommonStock TreasuryStock Share count as of January 1, 2011 — — — Share count as of December 31, 2011 — — — Issuance of common stock in pre IPO reorganization — 47,634,353 — Proceeds from the sale of common stock to public — 18,000,000 — Issuance of preferred stock as consideration in Eagle PropertyAcquisition — — — Share based compensation grants of restricted stock — 1,029,509 — Forfeitures of restricted stock (44,151) — Share count as of December 31, 2012 325,000 66,619,711 — Grants of restricted stock — 2,840,241 — Forfeitures of restricted stock — (534,207) — Acquisition of treasury stock — — (118,702) Share count as of December 31, 2013 325,000 68,925,745 (118,702) Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)10. Equity and Share-Based Compensation (Continued)Share-Based Compensation, pre Initial Public Offering During the year ended December 31, 2011, certain restricted and unrestricted shares in Petroleum Inc., through which Holdings LLC's founders,members of management and certain employees previously held their equity interests, certain unrestricted units in Holdings LLC, and certain units inMidstates Incentive Holdings, LLC ("Midstates Incentive") had been issued to employees of Holdings LLC. Additionally, in March 2011, Holdings LLC's Chief Executive Officer, in connection with the commencement of his employment, purchased 17.3shares of common stock of Petroleum Inc. and contemporaneously received a grant of 24.6 shares of common stock in Petroleum Inc. that vested asdescribed further below. No other shares or units were issued during the 2011 period. The Company determined the grant date fair value of the sharebased award to be $80,013 per Petroleum Inc. share ($3.4 million in aggregate), or after taking into account the corporate reorganization attributable tothe initial public offering completed on April 25, 2012, $4.26 per share of the Company's common stock. The Company recognized stock compensationbased upon the grant date fair value and immediately expensed the difference between the grant date fair value and the price paid for the purchasedshares of Petroleum Inc., as well as additional compensation expense related to the liability accounting for the Company's share-based awards discussedbelow. Prior to December 5, 2011, due to certain rights to call shares and units in Holdings LLC for cash, Holdings LLC's share-based payments awardedto employees were accounted for as liability awards. As such, Holdings LLC calculated the fair value of the share-based awards on a quarterly basisusing estimated market value and the total fair value of the awards was recorded within "Other long-term liabilities" in Holding LLC's consolidatedbalance sheets. Any change in the fair value of the liability awards was recorded as share-based compensation expense within "General andadministrative expense" in Holdings LLC's consolidated statements of operations, which was the same line item as cash compensation paid to the sameemployees. Historically, Holdings LLC's determination of the fair value of each of the units was affected by: (i) Holdings LLC's risk adjusted proved,possible, and probable reserves; (ii) internal assessment of long-term commodity prices; (iii) current values of Holdings LLC's non-oil and gas assetsand liabilities; and (iv) a number of complex and subjective variables. Although the fair value of the share-based payments is determined in accordancewith GAAP, that value may not be indicative of the fair value observed in a market transaction between a willing buyer and a willing seller. Effective as of November 22, 2011, the Board of Directors of Petroleum Inc. accelerated the vesting of all restricted stock in Petroleum Inc. Thevesting resulted in the recognition of previously unrecognized share-based compensation expense at the estimated fair market value of the restrictedstock held by employees at November 22, 2011. Petroleum Inc. determined the fair market value of Petroleum Inc.'s common stock based onmanagement's estimates. On December 5, 2011, Employment Agreements with employees of Midstates Petroleum Company LLC, a Stockholders' Agreement by andamong stockholders in Petroleum Inc. and a Unitholders' Agreement by and among the members of Holdings LLC were either terminated or amendedsuch that the rights within those agreements to call shares in Petroleum Inc. and units in Holdings LLC for cash no longer required Holdings LLC'sshare-based payments awarded to employees to be accounted for as liability awards. As a result the Company transitioned as of December 5, 2011 fromliability accounting to equity accounting for the Company's share-based compensation plans and accordingly, the Company no longer recognizedchanges in the estimated fair value of outstanding share-based awards in the statements of operations.F-31Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)10. Equity and Share-Based Compensation (Continued)Restricted Shares. Restricted shares in Petroleum Inc. were awarded at no cost to the recipient with a vesting period that commenced on the grant date and terminatedon the fifth anniversary or upon certain changes in control of Holdings LLC, including but not limited to mergers, acquisitions, or a public offering. As a result of the vesting on November 22, 2011, as discussed above, there is no unrecognized compensation cost and as a result of the corporatereorganization in April 2012, each share of Petroleum Inc. was converted into 18,762 shares of the Company's common stock. As a result, there are nooutstanding restricted shares in Petroleum Inc. as of December 31, 2013.Unrestricted Shares and Units. Unrestricted shares in Petroleum Inc. and units of Holdings LLC were either purchased by the recipient on the grant date and were fully vestedupon purchase, or represented restricted shares which vested. For shares of Petroleum Inc. and units of Holdings LLC purchased, any differencebetween the recipient's purchase price and the grant date fair value was recognized as compensation expense on the grant date. As a result of thecorporate reorganization in April 2012, each share of Petroleum, Inc. and each unit of Holdings LLC were converted into 18,762 and 185.5 sharesrespectively, of the Company's common stock. As a result, at December 31, 2013, there are no Petroleum, Inc. shares or Holdings LLC unitsoutstanding.Incentive Units. At December 31, 2013, 1,513 incentive units were issued and outstanding. In connection with the corporate reorganization that occurredimmediately prior to our initial public offering, these incentive units held in the Company were contributed to FR Midstates Interholding, LP ("FRMI")in exchange for incentive units in FRMI. Holders of FRMI incentive units will receive, out of proceeds otherwise distributable to FRMI, a percentageinterest in the amounts distributed to FRMI in excess of certain multiples of FRMI's aggregate capital contributions and investment expenses ("FRMIProfits"). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FRMI and not by theCompany, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the FRMI incentiveunits. To date, no compensation expense related to the incentive units has been recognized by the Company, as any payout under the incentive units isnot considered probable, and thus, the amount of FRMI Profits, if any, cannot be determined.Share-based Compensation, Post-Initial Public Offering2012 Long Term Incentive Plan. The Company established the 2012 Long Term Incentive Plan (the "2012 LTIP") and filed a Form S-8 with the SEC, registering 6,563,435 sharesfor future issuance under the terms of the 2012 LTIP. The 2012 LTIP provides a means for the Company to attract and retain employees, directors andconsultants, and a method whereby employees, directors and consultants of the Company who contribute to its success can acquire and maintain stockownership or awards, the value of which is tied to the performance of the Company, thereby strengthening their concern for the welfare of the Companyand their desire to remain employed. The 2012 LTIP provides for the granting of Options (Incentive and other), Restricted Stock Awards, Restricted Stock Units, Stock AppreciationRights, Dividend Equivalents, Bonus Stock, Other Stock-Based Awards, Annual Incentive Awards, Performance Awards, or any combination of theF-32Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)10. Equity and Share-Based Compensation (Continued)foregoing (the "Awards"). Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award are as determined by the CompensationCommittee of the Board of Directors. A total of 6,563,435 common share Awards are authorized for issuance under the 2012 LTIP and shares of stocksubject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awardsunder the 2012 LTIP.Non-vested Stock Awards. Subsequent to the completion of the Company's initial public offering and pursuant to the 2012 LTIP, through December 31, 2013 the Companyhad 2,963,672 shares of restricted common stock to directors, management and employees outstanding. Shares granted under the LTIP generally vestratably over a period of three years (one-third on each anniversary of the grant), however, beginning in 2013, shares granted under the 2012 LTIP todirectors are subject to one-year cliff vesting. The fair value of restricted stock grants is based on the value of the Company's common stock on the date of grant. Compensation expense isrecognized ratably over the requisite three year service period. The following table summarizes the Company's non-vested share award activity for the years ended December 31, 2013 and 2012: Unrecognized expense as of December 31, 2013 for all outstanding restricted stock awards, adjusted for estimated forfeitures, was $16.3 millionand will be recognized over a weighted average period of 2.08 years. At December 31, 2013, 3,272,043 shares remain available for issuance under the terms of the 2012 LTIP.F-33 Shares WeightedAverageGrant DateFair Value Non-vested shares outstanding at December 31, 2011 — $— Granted 1,029,509 $12.63 Vested — $— Forfeited (44,151)$12.99 Non-vested shares outstanding at December 31, 2012 985,358 $12.61 Granted 2,840,241 $6.82 Vested (327,720)$12.62 Forfeited (534,207)$8.65 Non-vested shares outstanding at December 31, 2013 2,963,672 $7.78 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)10. Equity and Share-Based Compensation (Continued) The following table summarizes share-based compensation costs (net of amounts capitalized to oil and gas properties) recognized as general andadministrative expense by the Company for the periods presented (in thousands): For the years ended December 31, 2013 and 2012, the Company capitalized $1.4 million and $0.2 million, respectively, of qualifying share-basedcompensation costs to oil and gas properties.11. Income Taxes Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or stateincome tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as theCompany's equity holders were responsible for income tax on the Company's profits. In connection with the closing of the Company's initial publicoffering, the Company merged into a corporation and became subject to federal and state income taxes. The Company's book and tax basis in assets andliabilities differed at the time of the corporate reorganization due primarily to different cost recovery methodology utilized for book and tax purposes forthe Company's oil and natural gas properties. In the quarter ended June 30, 2012, the Company recorded a one-time charge to income tax expense of$149.5 million to recognize this deferred tax liability related to the Company's change in tax status caused by the initial public offering. The Company incurred a tax net operating loss ("NOL") in the current year due principally to the ability to expense certain intangible drilling anddevelopment costs under current law. There is no tax refund available to the Company, nor is there any current income tax payable. In light of theimpairment of oil and gas properties, Management has recorded a $45.7 million valuation allowance against the Company's federal and State ofLouisiana NOLs, as management does not believe that it is more-likely-than-not that this portion of the Company's NOLs are realizable. Managementbelieves that the balance of the Company's NOLs are realizable only to the extent of future taxable income primarily related to the excess of bookcarrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment. The Company's NOLs were incurred in the tax years 2012 and 2013, and U.S. federal and State of Oklahoma NOLs will generally be available foruse through the tax years 2032 and 2033, respectively, and its State of Louisiana NOLs are generally available through 2027 and 2028, respectively.The State of Texas currently has no NOL carryover provision. The Company believes that Section 382 of the Internal Revenue Code of 1986, asamended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period, willnot have an adverse effect on future NOL usage. On September 13, 2013, the US Treasury and IRS issued final Tangible Property Regulations ("TPR") under IRC Section 162 and IRCSection 263(a). The regulations are not effective until taxF-34 For the YearsEnded December 31, 2013 2012 2011 Restricted and unrestricted Petroleum Inc. shares and Holdings LLCunits $— $— $53,744 Incentive units — — — 2012 LTIP restricted shares 5,713 2,459 — Total share-based compensation expense $5,713 $2,459 $53,744 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)11. Income Taxes (Continued)years beginning on or after January 1, 2014; however, certain portions may require an accounting method change on a retroactive basis, thus requiring aIRC Section 481(a) adjustment related to fixed and real asset deferred taxes. The accounting rules under ASC 740 treat the release of the regulations as achange in tax law as of the date of issuance and require the Company to determine whether there will be an impact on its financial statements for theperiod ended December 31, 2013. Any such impact of the final tangible property regulations would affect temporary deferred taxes only and result in abalance sheet reclassification within non-current deferred taxes. The Company has analyzed the expected impact of the TPR on the Company andconcluded that the expected impact is minimal. The Company will continue to monitor the impact of any future changes to the TPR on the Companyprospectively. As of December 31, 2013, the Company has not recorded a reserve for any uncertain tax positions. No income tax payments are expected in theupcoming four quarterly reporting periods.F-35 Year Ended December 31, 2013 2012(1) Current United States $— $— State — — Total current — — Deferred United States (130,906) 137,496 State (15,623) 20,390 Total deferred (146,529) 157,886 Total income tax provision (benefit) $(146,529)$157,886 (1)For the 2011 comparable period, the calculation is not applicable as the Company was not a taxable entity until April 25,2012.Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)11. Income Taxes (Continued) The Company's estimated income tax expense differs from the amount derived by applying the statutory federal rate to pretax income principallydue the effect of the following items (in thousands): Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities forfinancial reporting purposes and the amounts used forF-36 Year Ended December 31, 2013 2012(1) Income before taxes $(490,514)$7,789 Statutory rate 35% 35% Income tax expense computed at statutory rate $(171,680)$2,726 Reconciling items: Non-deductible pre-IPO loss — 4,561 State income taxes, net of federal tax benefit (10,886) 1,053 Change in valuation allowance 45,688 Change in state rate (10,500) Other, net 849 57 Change in tax status(2) — 149,489 Tax provision (benefit) $(146,529)$157,886 (1)For the 2011 comparable period, the calculation is not applicable as the Company was not a taxable entity until April 25,2012. (2)The change in tax status for the year ended December 31, 2012 is split between federal of $130.2 million and state of$19.3 million.Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)11. Income Taxes (Continued)income tax purposes. The components of our deferred taxes are detailed in the table below (in thousands):12. Earnings (Loss) Per Share The Company's Series A Preferred Stock issued in connection with the Eagle Property Acquisition has the nonforfeitable right to participate on anas converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. TheCompany's nonvested stock awards, which are granted as part of the 2012 LTIP, contain nonforfeitable rights to dividends and as such, are consideredto be participating securities and, together with the Series A Preferred Stock, are included in the computation of basic and diluted earnings (loss) pershare, pursuant to the two-class method. In the calculation of basic earnings (loss) per share attributable to common shareholders, participating securitiesare allocated earnings based on actualF-37 December 31,2013 December 31,2012(1)(2) Deferred tax assets—current Derivative instruments and other $15,581 $6,027 Less valuation allowance (3,744) — Total deferred tax assets, current $11,837 $6,027 Deferred tax assets—noncurrent US tax loss carryforwards 151,872 90,735 State tax loss carryforwards 14,154 12,258 Employee benefit plans 1,539 985 Less valuation allowance (41,944) — Total deferred tax assets, noncurrent $125,621 $103,978 Deferred tax liabilities—noncurrent Oil and gas properties and equipment(1) 140,912 260,715 Total deferred tax liabilities, noncurrent $140,912 $260,715 Reflected in the accompanying balance sheet as: Net deferred tax asset, current $11,837 $6,027 Net deferred tax liability noncurrent $15,291 $156,737 (1)For December 31, 2012, oil and gas properties and equipment includes a deferred tax liability of $26.7 million which wasrecognized as a result of the Eagle Property Acquisition. The difference originated in the tax bases and the recognizedvalue for GAAP purposes of the assets acquired and liabilities assumed in the Eagle Property Acquisition. (2)In the third quarter of 2013, the Company determined that its 2012 accounting for the tax impacts of the merger of certainentities that occurred in connection with the Company's initial public offering was in error. The Company identified thatcertain tax attributes acquired from the merged entities were not properly identified. Because the tax attributes wereacquired as a result of a merger of entities under common control, the impacts of these tax attributes should have beenrecorded through equity at the time the Company became a taxable entity.Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)12. Earnings (Loss) Per Share (Continued)dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizingdistributed earnings. The Company's participating securities do not participate in undistributed net losses because they are not contractually obligated todo so. The computation of diluted earnings per share attributable to common shareholders reflects the potential dilution that could occur if securities orother contracts to issue common shares that are dilutive were exercised or converted into common shares (or resulted in the issuance of common shares)and would then share in the earnings of the Company. During the periods in which the Company records a loss from continuing operations attributableto common shareholders, securities would not be dilutive to net loss per share and conversion into common shares is assumed to not occur. Diluted netincome per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method; the more dilutive ofthe two calculations is presented below. The following table (in thousands, except per share amounts) provides a reconciliation of net losses to preferred shareholders, commonshareholders, and participating securities for purposes of computing net loss per share for the year ended December 31, 2013: The following table (in thousands, except per share amounts) provides a reconciliation of net losses to preferred shareholders, commonshareholders, and non-vested restricted shareholders for purposes of computing net loss per share for the year ended December 31, 2012:F-38 Total Series APreferredStock CommonStock Non-vestedRestrictedStock(2) Net loss $(343,985)$— $(343,985)$— Preferred Dividend(1) $(15,589) — (15,589) — Calculated allocation of net loss attributable to shareholders $(359,574)$— $(359,574)$— Weighted average shares outstanding 65,766 Net loss per share $(5.47) (1)Calculation of the preferred stock dividend is discussed in Note 10. (2)As these shares are participating securities that participate in earnings, but are not required to participate in losses, this calculationdemonstrates that there is not an allocation of the loss to the non-vested restricted stockholders. Total Series APreferredStock CommonStock Non-vestedRestrictedStock(2) Net loss $(150,097)$— $(150,097)$— Preferred Dividend(1) $(6,500) — (6,500) — Calculated allocation of net loss attributable to shareholders $(156,597)$— $(156,597)$— Weighted average shares outstanding 59,979 Net loss per share $(2.61) (1)Calculation of the preferred stock dividend is discussed in Note 10.Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)12. Earnings (Loss) Per Share (Continued)13. Concentrations of Credit Risk Financial instruments which potentially subject the Company to credit risk consist primarily of cash balances, accounts receivable and derivativefinancial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. TheCompany has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any onefinancial institution or company. The Company normally sells production to a relatively small number of purchasers, as is customary in the exploration, development andproduction business. The Company typically sells a substantial portion of production under short-term (usually one month) contracts tied to a localindex. The Company does not have any long-term, fixed-price sales contracts. For the year ended December 31, 2013, five purchasers accounted for28%, 16%, 13%, 12% and 11% respectively, of the Company's revenue. For the year ended December 31, 2012, three purchasers accounted for 41%,32% and 10%, respectively, of the Company's revenue. For the year ended December 31, 2011, two purchasers accounted for 39% and 38%,respectively, of the Company's revenue. Substantially all of the Company's accounts receivable result from the sale of oil, natural gas and natural gas liquids. At December 31, 2013, threepurchasers accounted for approximately 31%, 16%, and 13%, respectively, of the accounts receivable balance. At December 31, 2012, four purchasersaccounted for approximately 38%, 18%, 14% and 10%, respectively, of the accounts receivable balance. Derivative financial instruments are generally executed with major financial institutions that expose the Company to market and credit risks andwhich may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. TheCompany also has netting arrangements in place with counterparties to reduce credit exposure. The Company has not experienced any losses from suchinstruments.14. Commitments and ContingenciesContractual Obligations At December 31, 2013, contractual obligations for drilling contracts, long-term operating leases, seismic contracts and other contracts are asfollows (in thousands): For the years ended December 31, 2013, 2012 and 2011, the Company expensed $1.7 million, $1.1 million and $0.6 million, respectively, foroffice rent.F-39(2)As these shares are participating securities that participate in earnings, but are not required to participate in losses, this calculationdemonstrates that there is not an allocation of the loss to the non-vested restricted stockholders. Total 2014 2015 2016 2017 2018 andbeyond Drilling contracts $8,192 $8,192 $— $— $— $— Non-cancellable office leasecommitments $11,052 1,732 1,857 1,877 1,941 3,645 Seismic contracts $4,410 4,410 — — — — Net minimum commitments $23,654 $14,334 $1,857 $1,877 $1,941 $3,645 Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)14. Commitments and Contingencies (Continued) In addition to the commitments noted in the above table, the Company is party to a gas transportation, gathering and processing contract (asamended and effective June 1, 2013) in the Mississippian Lime region which includes certain minimum natural gas and NGL volume commitments. Tothe extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recoveredNGLs, the Company would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee ofroughly $0.06 to $0.125 per gallon (subject to annual escalation). The NGL volume commitments range from 2,800 bbls to 5,460 bbls per day over theremaining term of the contract. Additionally, the Company is obligated to deliver a total of 38,100,000 MMBTUs and 76,200,000 MMBTUs during thefirst 30 months and 60 months of the contract, respectively. During the first 30 months, any shortfall in delivered volumes would result in a payment tothe counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBTU. During the first 60 months, any shortfall indelivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBTU,provided that the Company would receive volumetric credit for any deficiency payment made after the initial 30 months. The Company is currentlydelivering at least the minimum volumes required under these contractual provisions and does not expect to incur any future volumetric shortfallpayments during the term of this contract. Commitments related to ARO's are not included in the table above; see Note 7 for discussion of those commitments.Litigation We are involved in disputes or legal actions arising in the ordinary course of our business. We may not be able to predict the timing or outcome ofthese or future claims and proceedings with certainty, and an unfavorable resolution of one or more of such matters could have a material adverse effecton our financial condition, results of operations or cash flows. Currently, we are not party to any legal proceedings that, individually or in the aggregate,are reasonably expected to have a material adverse effect on our financial position, results of operations, or cash flows.15. Subsequent Events On March 5, 2014, the Company executed a Purchase and Sale Agreement ("PSA") to sell all of its ownership interest in developed andundeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for a purchase price of $170 million in cash, subjectto standard post-closing adjustments. Acreage subject to the transaction does not include the Company's acreage and production in the western part ofLouisiana in Beauregard Parish or other undeveloped acreage held outside the Pine Prairie field. The proceeds from the sale will be used to pay downthe Company's revolving credit facility. The PSA has an effective date of November 1, 2013 and is expected to close on May 1, 2014. Additionally, in order to provide additional capital resources during 2014, the Company entered into commitment letters with SunTrust Bank,SunTrust Robinson Humphrey, Inc., Morgan Stanley Senior Funding, Inc., Bank of America N.A., Goldman Sachs Bank USA, Merrill Lynch, Piece,Fenner & Smith Incorporated, Natixis New York Branch and Royal Bank of Canada on March 9, 2014 to, among other things, provide for a SeniorSecured Bridge Facility ("Bridge Facility") in the amount of $125 million and to provide for a commitment ("RBL Backstop") to provide a backstoprevolver credit facility in the event that an amendment to our existing revolving credit facility to permit the consummation of the Bridge Facility and arevised borrowing base of $475 million cannot be obtained.F-40Table of ContentsMIDSTATES PETROLEUM COMPANY, INC.Notes to Consolidated Financial Statements (Continued)15. Subsequent Events (Continued) The Bridge Facility would be secured by a first priority lien on the Company's Gulf Coast assets and a second lien on its Mississippian andAnadarko assets. Any obligations under the Bridge Facility would be guaranteed by the same entities that guaranty the existing credit facility. Advancesunder the Bridge Facility would be available through September 30, 2014, would be funded in tranches of $50 million (subject to availability), initiallybear interest at LIBOR plus 4.5% (subject to a 0.50% increase in interest rate at September 30, 2014, December 31, 2014 and March 31, 2015) andmature on the first anniversary of the closing date. Interest on any advances is payable quarterly in cash. Upon maturity, any amounts outstanding on theBridge Facility would be converted into a senior secured term loan or, at any time thereafter at the option of the lenders, into senior secured exchangenotes maturing in September 2019. Additionally, lenders under the Bridge Facility will have a securities demand if total liquidity (as defined therein)falls below $50 million, provided that this provision will not apply until June 1, 2014, so long as the executed PSA discussed above remains in place.The Bridge Facility would be pre-payable in whole or in part without penalty or premium and would be subject to mandatory prepayment in the event ofLouisiana asset sales (including the Pine Prairie transaction discussed above), issuance of debt or equity, occurrence of a change in control or certainother events. The Company has agreed to pay a 1.75% commitment fee, a 1.25% funding fee and a 2.25% fee upon the rollover. The definitive loandocumentation for the Bridge Facility will include certain representations and warranties, affirmative, negative and financial covenants and events ofdefault customary for bridge loan financings, including limitations on incurrence of indebtedness that, prior to any rollover, will be more restrictive thanthose contained in the existing credit facility. In the event that an amendment accommodating the Bridge Facility, the transactions contemplated thereby and a borrowing base of $475 millioncannot be obtained under the existing credit facility, the RBL Backstop provides a commitment to provide a new credit facility on substantially the sameterms as the existing credit facility, including the notional amount of $750 million and a maturity date of May 2018, but with appropriate modificationsto (i) release the Louisiana assets from the borrowing base facility to allow for the Bridge Facility and the potential sale pursuant to the PSA, (ii) reducethe borrowing base under the existing credit facility from $500 million to $475 million, (iii) increase the leverage ratio by 0.50 for the quarter of and thetwo quarters following the sale of Pine Prairie for net proceeds greater than $100 million, (iv) allow for the Bridge Facility to be secured by a secondlien on the Mississippian and Anadarko assets, and (v) increase the applicable interest rate under the existing credit facility by 0.25%. Lendersparticipating in the RBL Backstop are to receive an underwriting fee of 0.25% whether the RBL Backstop is utilized or not. In the event the existingcredit agreement is not amended for the above terms and the RBL Backstop is utilized, participating lenders will receive an additional underwriting feeof 1.00%. Other terms of the backstop credit facility would remain materially unchanged from those contained in the existing credit facility. The Company expects to execute the definitive documentation of the new reserve based credit facility and the Bridge Facility during first quarter of2014.F-41Table of ContentsSUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) The supplemental data presented herein reflects information for all of the Company's oil and natural gas producing activities.Capitalized Costs The following table sets forth the capitalized costs related to the Company's oil and natural gas producing activities at December 31, 2013 and 2012(in thousands):Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities The following table sets forth costs incurred related to the Company's oil and natural gas activities for the years ended December 31, 2013, 2012and 2011 (in thousands):Costs Not Being Amortized The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2013, by the year in which such costswere incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The evaluationactivities are expected to be completed within three to five years.F-42 December 31,2013 December 31,2012 Proved properties $2,817,062 $1,522,723 Less: Accumulated depreciation, depletion and amortization (973,646) (273,241) Proved Properties, net 1,843,416 1,249,482 Unproved properties 243,599 313,941 Total oil and gas properties, net $2,087,015 $1,563,423 Year Ended December 31, 2013 2012 2011 Acquisition costs: Proved properties $413,472 $416,688 $— Unproved properties 206,339 247,909 — Exploration costs 9,554 35,959 23,555 Development costs 583,017 415,403 242,764 Asset retirement costs 12,768 7,439 5,444 Total costs incurred $1,225,150 $1,123,398 $271,763 Total 2013 2012 2011 2010 andPrior Property acquisition costs, net $179,453 116,713 62,740 — — Exploration and development costs $44,843 33,246 8,690 1,281 1,626 Capitalized interest $19,303 19,303 — — — Total $243,599 $169,262 $71,430 $1,281 $1,626 Table of ContentsEstimated Quantities of Proved Oil and Natural Gas Reserves The reserve estimates at December 31, 2013, 2012 and 2011 for the Gulf Coast and Mississippian areas were based on reports prepared byNetherland, Sewell and Associates, Inc., independent reserve engineers, in accordance with the FASB's authoritative guidance on oil and gas reserveestimation and disclosures. The reserve estimates at December 31, 2013 for the Anadarko Basin area were based on reports prepared by CawleyGillespie & Associates, Inc., independent reserve engineers, in accordance with the FASB's authoritative guidance on oil and gas reserve estimation anddisclosures. At December 31, 2013, all of the Company's oil and natural gas producing activities were conducted within the continental United 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 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 which geological and engineeringdata demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions(i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected tobe recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.F-43Table of Contents The following table sets forth the Company's net proved, proved developed and proved undeveloped reserves at December 31, 2013, 2012 and2011(1):F-44 Oil(MBbl) NGL(MBbl) Gas(MMcf) Total (MBoe) 2011 Proved Reserves Beginning Balance 11,927 314 27,906 16,892 Revision of previous estimates (2,650) 1,661 (6,500) (2,072)Extensions, discoveries and other additions 8,049 2,364 22,204 14,114 Sales of reserves in place — — — — Purchases of reserves in place — — — — Production (1,610) (308) (4,918) (2,738) Net proved reserves at December 31, 2011 15,716 4,031 38,692 26,196 Proved developed reserves, December 31, 2011 6,479 1,802 17,987 11,279 Proved undeveloped reserves, December 31, 2011 9,237 2,229 20,705 14,917 2012 Proved Reserves Beginning Balance 15,716 4,031 38,692 26,196 Revision of previous estimates (1,368) (193) (8,533) (2,982)Extensions, discoveries and other additions 12,262 3,232 32,646 20,935 Sales of reserves in place — — — — Purchases of reserves in place 13,010 7,745 85,293 34,969 Production (2,093) (617) (5,695) (3,659) Net proved reserves at December 31, 2012 37,527 14,198 142,403 75,459 Proved developed reserves, December 31, 2012 13,207 5,437 54,775 27,774 Proved undeveloped reserves, December 31, 2012 24,320 8,761 87,628 47,685 2013 Proved Reserves Beginning Balance 37,527 14,198 142,403 75,459 Revision of previous estimates (13,511) (3,259) (20,762) (20,230)Extensions, discoveries and other additions 17,538 8,812 103,551 43,608 Sales of reserves in place — — — — Purchases of reserves in place 17,242 8,124 73,653 37,642 Production (3,897) (1,719) (18,647) (8,724) Net proved reserves at December 31, 2013 54,899 26,156 280,198 127,755 Proved developed reserves, December 31, 2013 19,853 10,321 111,410 48,743 Proved undeveloped reserves, December 31, 2013 35,046 15,835 168,788 79,012 (1)The following table sets forth the benchmark prices used to determine our estimated proved reserves for the periods indicated.Table of Contents Purchases of Reserves in Place In 2013, the Company had a total of 37,642 MBoe of additions from purchases of reserves in place primarily as a result of the Anadarko BasinAcquisition, which closed on May 31, 2013 (see Note 6). The acquired assets included interests in producing oil and natural gas assets and leaseholdacreage in Texas and Oklahoma. In 2012, the Company had a total of 34,969 MBoe of additions from purchases of reserves in place as a result of the Eagle Property Acquisitionwhich closed on October 1, 2012 (see Note 6). The acquired assets included interests in producing oil and natural gas assets and unevaluated leaseholdacreage in Oklahoma and Kansas.Extensions, Discoveries and Other Additions In 2013, the Company had a total of 43,608 MBoe of additions from extensions and discoveries. Approximately 34,300 MBoe related to theMississippian area, while the remaining 9,300 MBoe related to the Anadarko Basin and Gulf Coast areas. In 2012, the Company had a total of 20,935 MBoe of additions from extensions and discoveries as a result of infill drilling and field delineationactivities. Approximately 16,500 MBoe related to the Gulf Coast area, while the remaining 4,400 MBoe related to the Mississippian area. In the GulfCoast, Pine Prairie had the largest increase with approximately 13,100 MBoe. In 2011, the Company had a total of 14,114 MBoe of additions from extensions and discoveries as a result of infill drilling and field delineationactivities. Approximately 6,200 MBoe were from Pine Prairie, 5,500 MBoe were from West Gordon, 2,200 MBoe were from South BearheadCreek/Oretta and 200 MBoe were from a new expansion area.Sales of Reserves in Place There were no sales of reserves in place since January 1, 2010.Revision of Previous Estimates In 2013, the Company had net negative revisions of 20,230 MBoe, of which approximately 17,800 MBoe related to the Gulf Coast. Of theserevisions in the Gulf Coast, approximately 9,500 MBoe related to Pine Prairie and were driven by higher development and lease operating costs whichresulted in certain proved undeveloped locations becoming uneconomic as of December 31, 2013, and approximately 4,900 MBoe related to WestGordon, primarily due to poor drilling results. In 2012, the Company had net negative revisions of 2,982 MBoe, of which 1,573 MBoe related to West Gordon. In 2011, the Company had net negative revisions of 2,072 MBoe primarily due to production performance in South Bearhead Creek and NorthCowards Gully, partially offset by positive revisions in Pine Prairie.F-45 At December 31, 2013 2012 2011 Oil, NGL and Natural Gas Prices: Oil (per barrel ("Bbl")) $97.18 $98.64 $111.59 NGL (per Bbl) $36.36 $36.84 $56.74 Natural gas (per million British thermal units ("MMBtu")) $3.286 $2.648 $4.100 Table of ContentsStandardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves The Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural reserves, less futuredevelopment, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cashflows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs. Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and naturalgas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The average adjusted product pricesweighted by production over the remaining lives of the properties for the years ended December 31, 2013 were $97.18/Bbl for oil, $36.36/Bbl forNGLs and $3.286 for natural gas. The average adjusted product prices weighted by production over the remaining lives of the properties for the yearsended December 31, 2012 were $98.64/Bbl for oil, $36.84/Bbl for NGLs and $2.648 for natural gas. The average adjusted product prices weighted byproduction over the remaining lives of the properties for the years ended December 31, 2011 were $111.59/Bbl for oil, $56.74/Bbl for NGLs and$4.100 for natural gas. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductionsand other factors affecting the price received at the wellhead. The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company's oil andnatural gas reserves at December 31, 2013, 2012, and 2011.F-46 At December 31, 2013 2012 2011 (in thousands) Future cash inflows $7,206,900 $4,654,893 $2,141,204 Future production costs 2,356,495 1,314,592 606,265 Future development costs 1,253,144 801,942 413,155 Future income tax expense(1) 510,400 587,745 — Future net cash flows 3,086,861 1,950,614 1,121,784 10% annual discount for estimated timing of cash flows (1,296,415) (801,140) (429,039) Standardized measure of discounted future net cash flows $1,790,446 $1,149,474 $692,745 (1)Does not include the effects of income taxes on future revenues at December 31, 2011 because as of December 31, 2011, theCompany was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or statecorporate income taxes has been provided because taxable income was passed through to the company's equity holders.Following its corporate reorganization, the Company is a corporation and subject to U.S. federal and state income taxes. If theCompany had been subject to entity-level taxation at December 31, 2011, the unaudited pro forma future income tax expense atDecember 31, 2011 would have been $127,534. The unaudited pro forma Standardized Measure at December 31, 2011 wouldhave been $565,211.Table of Contents The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gasreserves for the periods presented.F-47 Year Ended December 31, 2013 2012 2011 January 1, $1,149,474 $692,745 $298,088 Net changes in prices and production costs (83,055) (58,699) 214,601 Net changes in future development costs 49,170 768 (5,446)Sales of oil and natural gas, net (411,953) (202,884) (184,055)Extensions 579,945 639,532 361,485 Discoveries — — — Purchases of reserves in place 603,695 422,341 — Revisions of previous quantity estimates (399,210) (78,866) (31,833)Previously estimated development costs incurred 139,377 62,122 46,691 Accretion of discount 148,909 69,274 29,809 Net change in income taxes 54,326 (339,613) — Changes in timing, other (40,232) (57,246) (36,595) Period End $1,790,446 $1,149,474 $692,745 Table of ContentsSELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) The following table presents selected quarterly financial data derived from the Company's unaudited interim financial statements. The followingdata (in thousands, except per share amounts) is only a summary and should be read with the Company's historical consolidated financial statements andrelated notes contained in this document.F-48 Quarters Ended FirstQuarter SecondQuarter ThirdQuarter FourthQuarter (in thousands, except per share amounts) 2013 Total revenues $71,022 $126,008 $111,505 $160,971 Operating income (loss) (2,060) 21,947 (10,871) (416,425)Net income (loss) (7,949) 3,338 (23,606) (315,768)Net income (loss) attributable to common shareholders (12,066) 769 (26,175) (322,102)Net income (loss) per share: Basic and Diluted $(0.18)$0.01 $(0.40)$(4.89)Shares used in computation: Basic and Diluted 65,634 68,441 65,821 65,842 2012 Total revenues $30,244 $102,582 $25,932 $88,915 Operating income (loss) (15,824) 57,387 (28,567) 7,547 Net income (loss) (17,507) (112,377) (17,803) (2,410)Net income (loss) attributable to common shareholders (17,507) (112,377) (17,803) (8,910)Net income (loss) per share:(1) Basic and Diluted N/A $(1.85)$(0.27)$(0.14)Shares used in computation: Basic and Diluted N/A 60,887 65,634 65,634 (1)For the second quarter of 2012, the calculations of net income (loss) per share and shares used in computation are pro forma. Forthe first quarter of 2012, the calculation is not applicable as the Company was not a public company until April 25, 2012. Seefurther discussion in Note 12 in the Consolidated Financial Statements.Exhibit 10.10 EXECUTIVE EMPLOYMENT AGREEMENT This Executive Employment Agreement (the “Agreement”) is made and entered into as of April 25, 2012 (the “Effective Date) by and betweenMIDSTATES PETROLEUM COMPANY, INC., (the “Company”), and Nelson M. Haight (the “Executive”). In consideration of the respective agreements and covenants set forth in this Agreement, the receipt of which is hereby acknowledged, the partiesintending to be legally bound agree as follows: AGREEMENTS 1. Term. The Company agrees to employ Executive, and Executive agrees to be employed by the Company, upon the terms and conditionsset forth in this Agreement for a period (the “Initial Term”) commencing on the Effective Date and ending on the second anniversary of such date, unlessearlier terminated in accordance with Section 3. If neither party gives at least sixty (60) days written notice to the other party that it intends for this Agreementto terminate on such second anniversary, then this Agreement shall continue for successive one year terms (each a “Renewal Term”), unless earlier terminatedin accordance with Section 3, until either party gives at least sixty (60) days written notice to the other party that the other party intends for this Agreement toterminate at the end of any such one year period. The Initial Term and any Renewal Terms shall, together, constitute the “Term”. 2. Terms of Employment. (a) Position and Duties. (1) During Term, the Executive shall serve as Vice President and Controller and, in so doing, shall perform the duties andresponsibilities consistent with the position set forth above in a company of the size and nature of the Company, and such other duties, responsibilities, andauthority assigned to the Executive from time to time by the Board of Directors of the Company (the “Board”) or such other officer of the company as shall bedesignated by the Board. (2) During the Term, the Executive agrees to devote his full working time to the business and affairs of the Company and touse his best efforts to perform faithfully, effectively and efficiently his duties. The Executive covenants, warrants and represents that he shall: (i) devote hisfull and best efforts to the fulfillment of his employment obligations; (ii) exercise the highest degree of fiduciary loyalty and care and the highest standards ofconduct in the performance of his duties; and (iii) endeavor to prevent any harm, in any way, to the business or reputation of the Company or its affiliates. (b) Compensation. (1) Base Salary. During the Term, the Executive shall receive an annualized base salary (“Base Salary”), which shall bepaid in accordance with the customary payroll practices of the Company, in an amount equal to $200,000.00. The Board (or a committee of the Board,designated by the Board to make such decisions), in its sole discretion, 1 may at any time adjust (but not decrease below the aforementioned amount) the amount of the Base Salary as it may deem appropriate, and the term “BaseSalary,” as used in this Agreement, shall refer to the Base Salary as it may be so adjusted. (2) Bonus, Incentive, Savings, Profit Sharing and Retirement Plans. During the Term, and subject to the terms andconditions of applicable plans or programs, the Executive shall be eligible to participate in all bonus, incentive, savings, profit sharing and retirement plans,practices, policies and programs applicable generally to other similarly situated employees of the Company, as adopted or amended from time to time (“Incentive Plans”). The Company may in its sole discretion, from time to time, award the Executive bonus, incentive or other compensation under suchIncentive Plans in such amounts and at such times as the Board determines. (3) Welfare Benefit Plans. During the Term, and subject to the terms and conditions of applicable plans or programs, theExecutive and/or the Executive’s family, as the case may be, shall be eligible for participation in and shall receive all benefits under the welfare benefit plans,practices, policies and programs applicable generally to other similarly situated employees of the Company (which may include programs such as salarycontinuance, medical, prescription, dental, disability, employee life, group life, accidental death and travel accident insurance plans and programs), asadopted or amended from time to time (“Welfare Plans”). (4) Perquisites. During the Term, the Executive shall be entitled to receive (in addition to the benefits described above)such perquisites and fringe benefits appertaining to his position in accordance with any policies, practices, and procedures established by the Board, asamended from time to time. (5) Expenses. Executive is authorized to incur reasonable business expenses that, in Executive’s reasonable businessjudgment, are necessary to carry out his duties for the Company under this Agreement. Executive shall be entitled to reimbursement for such expenses, inaccordance with the Company’s standard procedures and policies, for all reasonable travel, entertainment and other expenses incurred in connection with theCompany’s business and the performance of his duties hereunder. (6) Vacation. During the Term, the Executive shall be entitled to four (4) weeks of paid vacation each calendar year,subject to the Company’s standard carryover policy. 3. Termination of Employment. (a) Death or Disability. The Executive’s employment shall terminate automatically upon the Executive’s death during the Term. Ifthe Disability of the Executive has occurred during the Term (pursuant to the definition of Disability set forth below), the Company may give to the Executivewritten notice in accordance with Section 10(c) of its intention to terminate the Executive’s employment. In such event, the Executive’s employment with theCompany shall terminate effective on the 30th day after receipt of such notice by the Executive (the “Disability Effective Date”), provided that, within the 30days after such receipt, the 2 Executive shall not have returned to perform, with or without reasonable accommodation, the essential functions of his position. For purposes of thisAgreement, “Disability” shall mean the Executive’s inability to engage in any substantial gainful activity by reason of any medically determinable physical ormental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months. (b) Cause. The Company may terminate the Executive’s employment at any time during the Term for Cause or without Cause. Forpurposes of this Agreement, “Cause” shall mean (1) a breach by the Executive of the Executive’s obligations under Section 2(a) (other than as a result ofphysical or mental incapacity) which constitutes nonperformance by the Executive of his obligations and duties thereunder, as determined by the Board(which may, in its sole discretion, give the Executive notice of, and the opportunity to remedy, such breach), (2) commission by the Executive of an act offraud, embezzlement, misappropriation, willful misconduct or breach of fiduciary duty against the Company or other conduct harmful or potentially harmfulto the Company’s best interest, as reasonably determined by a majority of the members of the Board after a hearing by the Board following ten (10) days’notice to the Executive of such hearing, (3) a material breach by the Executive of Sections 7 or 8 of this Agreement, (4) the Executive’s conviction, plea of nocontest or nolo contendere, deferred adjudication or unadjudicated probation for any felony or any crime involving fraud, dishonesty, or moral turpitude orcausing material harm, financial or otherwise, to the Company, (5) the refusal or failure of the Executive to carry out, or comply with, in any material respect,any lawful directive of the Board (which the Board, in its sole discretion, may give the Executive notice of, and an opportunity to remedy), (6) the Executive’sunlawful use (including being under the influence) or possession of illegal drugs; or (7) the Executive’s willful violation of any federal, state, or local law orregulation applicable to the Company or its business which adversely affects the Company. For purposes of the previous sentence, no act or failure to act onthe Executive’s part shall be deemed “willful” unless done, or omitted to be done, by the Executive not in good faith and without reasonable belief that theExecutive’s action or omission was in the best interest of the Company. The Company may suspend the Executive’s title and authority pending the hearingprovided for above. For purposes of this Agreement, a termination “without Cause” shall mean a termination by the Company of the Executive’semployment during the Term at the Company’s sole discretion for any reason other than a termination based upon Cause, death or Disability; provided that atermination “without Cause” does not include the expiration of the Term pursuant to Section 1. (c) Good Reason. The Executive’s employment may be terminated during the Term by the Executive for Good Reason or withoutGood Reason; provided, however, that the Executive agrees not to terminate his employment for Good Reason unless (x) the Executive has given the Companyat least 30 days prior written notice of his intent to terminate his employment for Good Reason, which notice shall specify the facts and circumstancesconstituting Good Reason, (y) the Company has not remedied such facts and circumstances constituting Good Reason within such 30-day period, and (z) theExecutive separates from service on or before the 60 day after the end of the 30-day cure period enumerated in the immediately preceding clause (y). Forpurposes of this Agreement, “Good Reason” shall mean any of the following, but only if occurring without the Executive’s consent: (1) a material diminutionin the Executive’s Base Salary, (2) a material diminution in the Executive’s authority, duties, or responsibilities, (3) the relocation of the Executive’s principaloffice to an area more than 50 miles from its location 3th immediately prior to such relocation, or (4) the failure of the Company to comply with any material provision of this Agreement. Such termination by theExecutive shall not preclude the Company from terminating the Executive’s employment prior to the Date of Termination (as defined below) established by theExecutive’s Notice of Termination (as defined below). (d) Notice of Termination. Any termination by the Company for Cause or without Cause or because of the Executive’s Disability, orby the Executive for Good Reason or without Good Reason, shall be communicated by Notice of Termination to the other party hereto given in accordance withSection 10(c). For purposes of this Agreement, a “Notice of Termination” means a written notice which (1) indicates the specific termination provision in thisAgreement relied upon, (2) to the extent applicable, sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of theExecutive’s employment under the provision so indicated and (3) if the Date of Termination (as defined below) is other than the date of receipt of such notice,specifies the termination date (which date shall not be more than 30 days after the giving of such notice). The failure by the Company or the Executive to setforth in the Notice of Termination any fact or circumstance which contributes to a showing of Cause or Good Reason, as applicable shall not waive any rightof the Company or the Executive under this Agreement or preclude the Company or the Executive from asserting such fact or circumstance in enforcing theCompany’s or Executive’s rights under this Agreement. (e) Date of Termination. “Date of Termination” means (1) if the Executive’s employment is terminated by the Company for Causeor without Cause, or by the Executive for Good Reason or without Good Reason, the date of receipt of the Notice of Termination or any later date specifiedtherein pursuant to Section 3(d), as the case may be, provided that if such date is not also the date of Executive’s “Separation from Service” with theCompany (within the meaning of Treasury Regulation 1.409A-1(h)) then the “Date of Termination” shall instead be the date of the Executive’s Separation fromService, or (2) if the Executive’s employment is terminated by reason of death or Disability, the date of death of the Executive or the Disability Effective Date,as the case may be. 4. Obligations of the Company upon Termination. (a) For Cause; Without Good Reason; Other Than for Death or Disability. If, during the Term, the Company shall terminate theExecutive’s employment for Cause or the Executive resigns from his employment without Good Reason, and the termination of the Executive’s employment inany case is not due to his death or Disability, or the Company shall have no further payment obligations to the Executive or his legal representatives, other thanfor the payment of: (1) in a lump sum in cash within thirty (30) days after the Date of Termination (or such earlier date as required by applicable law) thatportion of the Executive’s Annual Base Salary accrued through the Date of Termination to the extent not previously paid, any expense reimbursement accruedand unpaid, any employee benefits pursuant to the terms of the applicable employee benefit plan, and any accrued but unused vacation (the “AccruedObligations”); and (2) any accrued or vested amount arising from the Executive’s participation in, or benefits under, any Incentive Plans (the “AccruedIncentives”), which amounts shall be payable in accordance with the terms and conditions of such Incentive Plans. 4 (b) Death. If the Executive’s employment is terminated by reason of the Executive’s death during the Term, the Company shall haveno further payment obligations to the Executive or Executive’s legal representatives, other than for payment of: (1) a lump sum in cash within thirty (30) daysafter the Date of Termination (or such earlier date as required by applicable law) the Accrued Obligations; and (2) the Accrued Incentives, which shall bepayable in accordance with the terms and conditions of the Incentive Plans. (c) Disability. If the Executive’s employment is terminated by reason of the Executive’s Disability during the Term, the Companyshall have no further payment obligations to the Executive or his legal representatives, other than for payment of: (1) a lump sum in cash within thirty (30)days after the Date of Termination (or such earlier date as required by applicable law) the Accrued Obligations; and (2) the Accrued Incentives, which shall bepayable in accordance with the terms and conditions of the Incentive Plans. (d) Without Cause; For Good Reason. If the Executive’s employment is terminated by the Company without Cause before expirationof the Term, or if the Executive resigns for Good Reason before expiration of the Term, the Company shall have no further payment obligations to the Executiveor his legal representatives, other than for payment of: (1) in a lump sum in cash within thirty (30) days after the Date of Termination (or such earlier date asrequired by applicable law) the Accrued Obligations; (2) the Accrued Incentives, which shall be payable in accordance with the terms and conditions of theIncentive Plans; (3) subject to Section 4(f) below, a lump-sum cash payment, to be made on the first normal payroll date following the Release ConsiderationPeriod (the “Initial Severance Payment Date”) in an amount equal to (x) the average of the annual bonuses paid to the Executive for the three immediatelypreceding completed fiscal years, or (y) if upon the Date of Termination the Executive has not been employed for three complete fiscal years, then the average ofthe annual bonuses paid to the Executive for the years employed with the Company (the “Average Bonus”); and (4) subject to Section 4(f) below, beginningon the Initial Severance Payment Date and thereafter in accordance with the customary payroll practices of the Company, continuation of the Executive’s BaseSalary in effect on the Date of Termination (“Salary Continuation Payments”) for a period of 12 months. Any installments of the Severance Paymentsthat, in accordance with customary payroll practices, would have typically been made during the Release Consideration Period shall accumulate and shall thenbe paid on the Initial Severance Payment Date. The Average Bonus together with the Salary Continuation Payments shall be referred to collectively as the“Severance Payments”. (e) Protected Period: Without Cause; For Good Reason. If the Executive’s employment is terminated by the Company without Causebefore expiration of the Term, or if the Executive resigns for Good Reason before expiration of the Term, in each case, at any time during the Protected Period(as defined below), the Company shall have no further payment obligations to the Executive or his legal representatives, other than: (1) payment in a lump-sum in cash within thirty (30) days after the Date of Termination (or such earlier date as required by applicable law) the Accrued Obligations; (2) payment ofthe Accrued Incentives, which shall be payable in accordance with the terms and conditions of the Incentive Plans; (3) Subject to Section 4(f) below, on theInitial Severance Payment Date, all unvested awards granted to the Executive under the Midstates Petroleum Company, Inc. 2012 Long Term Incentive Plan(the “LTIP”) shall vest, except for (x) any annual cash bonuses granted under the LTIP, and (y) any 5 awards granted under Section 8 of the LTIP or otherwise intended to qualify as “qualified performance-based compensation” under Section 162(m) of theInternal Revenue Code (the “Code”) and any regulations or guidance promulgated thereunder; and (4) Subject to Section 4(f) below, on the Initial SeverancePayment Date, payment of a lump sum cash payment equal to the product of 2 multiplied by the sum of (x) the highest Base Salary paid to the Executiveduring the three years immediately preceding the Change in Control and (y) the highest annual bonus paid to the Executive for the three completed fiscal yearsimmediately preceding the Change in Control (the accelerated vesting enumerated in clause (3) of this Section 4(e), together with the payments enumerated inthis clause (4) of this Section 4(e), collectively the “CIC Severance Payments”). “Protected Period” means the period beginning on the date of a Change inControl (as defined below) and continuing until the one-year anniversary of such Change in Control. “Change in Control” shall have the meaning set forth inthe LTIP. (f) Release and Compliance with this Agreement. The obligation of the Company to pay any portion of the amounts due pursuant toSection 4, with the exception of Accrued Obligations and Accrued Incentives, shall be expressly conditioned on the Executive’s (1) execution (and, ifapplicable, non-revocation) of a full general release, releasing all claims, known or unknown, that the Executive may have against the Company, includingthose arising out of or in any way related to the Executive’s employment or termination of employment with the Company no later than the 60 day followingthe Date of Termination (such period, the “Release Consideration Period”) and (2) continued compliance with the requirements of Sections 7 and 8. (g) Section 409A. Other than the Severance Payments, the amounts payable pursuant to Section 4 of this Plan are intended tocomply with the short-term deferral exception to Section 409A of the Code. To the extent that a Participant is a “specified employee” within the meaning of theTreasury Regulations issued pursuant to Section 409A of the Code as of the Participant’s Date of Termination, no amount that constitutes a deferral ofcompensation which is payable on account of the Participant’s separation from service shall be paid to the Participant before the date (the “Delayed PaymentDate”) which is first day of the seventh month after the Participant’s Date of Termination or, if earlier, the date of the Participant’s death following such Dateof Termination. All such amounts that would, but for this Section 4(g), become payable prior to the Delayed Payment Date will be accumulated and paid onthe Delayed Payment Date. No interest will be paid by the Company with respect to any such delayed payments. For purposes of Section 409A of the Code,each payment or amount due under this Plan shall be considered a separate payment, and a Participant’s entitlement to a series of payments under this Plan isto be treated as an entitlement to a series of separate payments. 5. Excise Taxes. If the Board determines, in its sole discretion, that Section 280G of the Code applies to any compensation payable to theExecutive, then the provisions of this Section 5 shall apply. If any payments or benefits to which the Executive is entitled from the Company, any affiliate,any successor to the Company or an affiliate, or any trusts established by any of the foregoing by reason of, or in connection with, any transaction thatoccurs after the Effective Date (collectively, the “Payments,” which shall include, without limitation, the vesting of any equity awards or other non-cashbenefit or property) are, alone or in the aggregate, more likely than not, if paid or delivered to the Executive, to be subject to the tax imposed by Section 4999of the Code or any successor provisions to that section, then the Payments (beginning with 6th any Payment to be paid in cash hereunder), shall be either (a) reduced (but not below zero) so that the present value of such total Payments received by theExecutive will be one dollar ($1.00) less than three times the Executive’s “base amount” (as defined in Section 280G(b)(3) of the Code) and so that no portionof such Payments received by the Executive shall be subject to the excise tax imposed by Section 4999 of the Code, or (b) paid in full, whichever of (a) or(b) produces the better net after tax position to the Executive (taking into account any applicable excise tax under Section 4999 of the Code and any otherapplicable taxes). The determination as to whether any Payments are more likely than not to be subject to taxes under Section 4999 of the Code and as towhether reduction or payment in full of the amount of the Payments provided hereunder results in the better net after tax position to the Executive shall be madeby the Board and the Executive in good faith. 6. Full Settlement. Neither the Executive nor the Company shall be liable to the other party for any damages for breach of this Agreementin addition to the amounts payable under Section 4 arising out of the termination of the Executive’s employment prior to the end of the Term; provided,however, that the Company shall be entitled to seek damages from the Executive for any breach of Sections 7 or 8 by the Executive or for the Executive’scriminal misconduct. 7. Confidential Information. (a) The Executive acknowledges that the Company has trade, business and financial secrets and other confidential and proprietaryinformation (collectively, the “Confidential Information”) which shall be provided to the Executive during the Executive’s employment by the Company. Confidential information includes, but is not limited to, sales materials, technical information, strategic information, business plans, processes andcompilations of information, records, specifications and information concerning customers or venders, customer lists, and information regarding methods ofdoing business. (b) The Executive is aware of those policies implemented by the Company to keep its Confidential Information secret, includingthose policies limiting the disclosure of information on a need-to-know basis, requiring the labeling of documents as “confidential,” and requiring the keepingof information in secure areas. The Executive acknowledges that the Confidential Information has been developed or acquired by the Company through theexpenditure of substantial time, effort and money and provides the Company with an advantage over competitors who do not know or use such ConfidentialInformation. The Executive acknowledges that all such Confidential Information is the sole and exclusive property of the Company. (c) During, and all times following, the Executive’s employment by the Company, the Executive shall hold in confidence and notdirectly or indirectly disclose or use or copy or make lists of any Confidential Information: except (i) to the extent authorized in writing by the Board; (ii) wheresuch information is, at the time of disclosure by the Executive, generally available to the public other than as a result of any direct or indirect act or omissionof the Executive in breach of this Agreement; or (iii) where the Executive is compelled by legal process, other than to an employee of the Company or a personto whom disclosure is reasonably 7 necessary or appropriate in connection with the performance by the Executive of his duties as an employee of the Company. The Executive agrees to usereasonable efforts to give the Company notice of any and all attempts to compel disclosure of any Confidential Information, in such a manner so as to providethe Company with written notice at least five (5) days before disclosure or within one (1) business day after the Executive is informed that such disclosure isbeing or will be compelled, whichever is earlier. Such written notice shall include a description of the information to be disclosed, the court, governmentagency, or other forum through which the disclosure is sought, and the date by which the information is to be disclosed, and shall contain a copy of thesubpoena, order or other process used to compel disclosure. (d) The Executive will take all necessary precautions to prevent disclosure to any unauthorized individual or entity. The Executivefurther agrees not to use, whether directly or indirectly, any Confidential Information for the benefit of any person, business, corporation, partnership, or anyother entity other than the Company. (e) As used in this Section 7, “Company” shall include Midstates Petroleum Company, Inc. and any of its affiliates. 8. Non-Competition; Non-Solicitation. (a) The Executive acknowledges and agrees that the nature of the Confidential Information which the Company commits to providehim during his employment by the Company would make it difficult, if not impossible, for him to perform in a similar capacity for a Competing Business(as defined below) without disclosing or utilizing the Confidential Information. Further, the Executive acknowledges that the Company shall, during the timethat the Executive is employed by Company, (a) disclose or entrust to the Executive, and provide the Executive access to, or place the Executive in a position tocreate or develop, trade secrets or Confidential Information belonging to the Company, (b) place the Executive in a position to develop business goodwillbelonging to the Company and (c) disclose or entrust to the Executive business opportunities to be developed for the Company. Accordingly, in considerationof the foregoing, the Executive agrees that he will not (other than for the benefit of the Company pursuant to this Agreement) directly or indirectly, individuallyor on behalf of any other person, firm, corporation or other entity (whether as an officer, director, employee, shareholder, consultant, contractor, partner, jointventurer, agent, equity owner or in any capacity whatsoever) (1) during the term of Non-Competition (as defined below), carry on or engage in the business ofdeveloping and/or implementing drilling and completion techniques to oil-prone resources in previously discovered yet underdeveloped hydrocarbon trends orin any other business activity that the Company is conducting, or is intending to conduct, on the Date of Termination, in each case in the parishes within theState of Louisiana listed in Exhibit A to this Agreement, the State of Texas, and any other geographical area in which the Company conducts business and, asof the Date of Termination, was planning to conduct business and to which the Executive’s duties as an employee of the Company related (a “CompetingBusiness”), or (2) during the Term of Non-Solicitation (as defined below), (i) hire, attempt to hire, or contact or solicit with respect to hiring any employee,officer, or consultant of the Company, or (ii) solicit, divert or take away any customers, customer leads, or suppliers (as of the Date of Termination) of theCompany. The “Term of Non-Competition” and the “Term of Non-Solicitation” shall be defined as that term beginning on the Effective Date andcontinuing until (x) if the Executive’s employment is 8 terminated by reason of death or Disability, the Date of Termination, or (y) if the Executive’s employment is terminated by the Company for Cause or withoutCause, or by the Executive for Good Reason or without Good Reason, the date that is the one year anniversary of the Date of Termination. (b) Notwithstanding the restrictions contained in Section 8(a), the Executive or any of the Executive’s affiliates may own an aggregateof not more than 2.0% of the outstanding stock of any class of a Competing Business, if such stock is listed on a national securities exchange or regularlytraded in the over-the-counter market by a member of a national securities exchange, without violating the provisions of Section 8(a), provided that neither theExecutive nor any of the Executive’s affiliates has the power, directly or indirectly, to control or direct the management or affairs of any such corporation andis not involved in the management of such corporation. (c) The Executive acknowledges that the geographic boundaries, scope of prohibited activities, and time duration of the precedingparagraphs are reasonable in nature and are no broader than are necessary to maintain the confidentiality and the goodwill of the Company and theconfidentiality of its Confidential Information and to protect the other legitimate business interests of the Company. The Executive further represents andacknowledges that (i) he or she has been advised by the Company to consult his or her own legal counsel in respect of this Agreement, and (ii) that he or shehas had full opportunity, prior to executing this Agreement, to review thoroughly this Agreement with his or her counsel. (d) If any court determines that any portion of this Section 8 is invalid or unenforceable, the remainder of this Section 8 shall notthereby be affected and shall be given full effect without regard to the invalid provisions. If any court construes any of the provisions of this Section 8, or anypart thereof, to be unreasonable because of the duration or scope of such provision, such court shall have the power to reduce the duration or scope of suchprovision and to enforce such provision as so reduced. (e) The Executive’s covenant under this Section 8 of the Agreement shall be construed as an agreement independent of any otherprovision of this Agreement; and the existence of any claim or cause of action of Executive against the Company, whether predicated on this Agreement orotherwise, shall not constitute a defense to the enforcement by the Company of this covenant. (f) As used in this Section 8, “Company” shall include Midstates Petroleum Company, Inc. and any of its affiliates. 9. Mutual Non-Disparagement. The Executive agrees not to intentionally make, or intentionally cause any other Person to make, anypublic statement that is intended to criticize or disparage the Company, any of its affiliates, or any of their respective officers, managers or directors. TheCompany agrees to use commercially reasonable efforts to cause its officers and members of its Board not to intentionally make, or intentionally cause anyother Person t make, any public statement that is intended to criticize or disparage the Executive. This Section 9 shall not be construed to prohibit any personfrom responding publicly to incorrect public statements or from making truthful statements when required by law, subpoena, court order, or the like. 9 10. Miscellaneous. (a) Survival and Construction. Executive’s obligations under this Agreement will be binding upon Executive’s heirs, executors,assigns, and administrators and will inure to the benefit of the Company, its subsidiaries, successors, and assigns. The language of this Agreement shall inall cases be construed as a whole according to its fair meaning, and not strictly for or against any of the parties. The section and paragraph headings used inthis Agreement are intended solely for the convenience of reference and shall not in any manner amplify, limit, modify, or otherwise be used in theinterpretation of any of the provisions hereof. (b) Definitions. As used in this Agreement, “affiliate” means, with respect to a person, any other person controlling, controlled byor under common control with the first person; the term “control,” and correlative terms, means the power, whether by contract, equity ownership orotherwise, to direct the policies or management of a person; and “person” means an individual, partnership, corporation, limited liability company, trust orunincorporated organization, or a government or agency or political subdivision thereof. (c) Notices. All notices and other communications hereunder shall be in writing and shall be given by hand delivery to the otherparty or by registered or certified mail, return receipt requested, postage prepaid, addressed as follows: If to the Executive:Nelson M. Haight3647 Blue Bonnet Blvd.Houston, TX 77025 If to the Company:Attn: Vice President of Human ResourcesMidstates Petroleum Company, Inc.4400 Post Oak Parkway, Suite 1900Houston, Texas 77027(713) 595-9400 or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notice and communications shall be effective whenactually received by the addressee. (d) Enforcement. If any provision of this Agreement is held to be illegal, invalid or unenforceable under present or future lawseffective during the term of this Agreement, such provision shall be fully severable; this Agreement shall be construed and enforced as if such illegal, invalidor unenforceable provision had never comprised a portion of this Agreement; and the remaining provisions of this Agreement shall remain in full force andeffect and shall not be affected by the illegal, invalid or unenforceable provision or by its severance from this Agreement. Furthermore, in lieu of such illegal,invalid or unenforceable provision there shall be added automatically as part of this Agreement a provision as similar in terms to such illegal, invalid orunenforceable provision as may be possible and be legal, valid and enforceable. 10 (e) Withholding. The Company may withhold from any amounts payable under this Agreement such Federal, state or local taxes asshall be required to be withheld pursuant to any applicable law or regulation as determined by the Company. (f) Section 409A Compliance. This Agreement is intended to comply with (or be exempt from) Code Section 409A and theprovisions of this Agreement shall be construed accordingly. To the extent that any in-kind benefits or reimbursements pursuant to this Agreement are taxableto Executive and constitute deferred compensation subject to Section 409A of the Code, any reimbursement payment due to Executive shall be paid toExecutive on or before the last day of the Executive’s taxable year following the taxable year in which the related expense was incurred. In addition, any suchin-kind benefit or reimbursement is not subject to liquidation or exchange for another benefit and the amount of such benefit or reimbursement that Executivereceives in one taxable year shall not affect the amount of such benefit and reimbursements that Executive receives in any other taxable year. The Executiveagrees to promptly submit and document any reimbursable expenses in accordance with the Company’s reasonable expense reimbursement policies to facilitatethe timely reimbursement of such expenses. (g) No Waiver. No waiver by either party at any time of any breach by the other party of, or compliance with, any condition orprovision of this Agreement to be performed by the other party shall be deemed a waiver of similar or dissimilar provisions or conditions at any time. (h) Equitable and Other Relief. The Executive acknowledges that money damages would be both incalculable and an insufficientremedy for a breach of Sections 7 or 8 by the Executive and that any such breach would cause the Company irreparable harm. Accordingly, the Company, inaddition to any other remedies at law or in equity it may have, shall be entitled, without the requirement of posting of bond or other security, to equitable relief,including injunctive relief and specific performance, in connection with a breach of Sections 7 or 8 by the Executive. In addition to the remedies the Companymay have at law or in equity, violation of Sections 7 or 8 herein will entitle the Company at its sole option not to pay the Average Bonus or the CIC SeverancePayments, to discontinue the Salary Continuation Payments to the Executive, and to seek repayment from the Executive of any Severance Payments or CICSeverance Payments already paid to him by the Company. Such remedies shall not be deemed to be liquidated damages and shall not be deemed the exclusiveremedies for a breach of this Section 7 or 8 but shall be in addition to all remedies available, at law or in equity, including the recovery of damages from theExecutive and his agents. No action taken by the Company under this Section 10(h) shall affect the enforceability of the release and waiver of claims executedby the Executive pursuant to Section 4(f)4(d). (i) Complete Agreement. The provisions of this Agreement constitute the entire and complete understanding and agreement betweenthe parties with respect to the subject matter hereof, and supersedes all prior and contemporaneous oral and written agreements, representations andunderstandings of the parties, which are hereby terminated. Other than expressly set forth herein, the Executive and Company acknowledge and represent thatthere are no other promises, terms, conditions or representations (or written) regarding any matter relevant hereto. This Agreement may be executed in two ormore counterparts. 11 (j) Arbitration. The Company and the Executive agree to the resolution by binding arbitration of all claims, demands, causes ofaction, disputes, controversies or other matters in question (“claims”), whether or not arising out of this Agreement or the Executive’s employment (or itstermination), whether sounding in contract, tort or otherwise and whether provided by statute or common law, that the Company may have against theExecutive or that the Executive may have against the Company or its parents, subsidiaries and affiliates, and each of the foregoing entities’ respective officers,directors, employees or agents in their capacity as such or otherwise; except that this agreement to arbitrate shall not limit the Company’s right to seek equitablerelief, including injunctive relief and specific performance, and damages and any other remedy or relief (including the recovery of attorney fees, costs andexpenses) in a court of competent jurisdiction for an alleged breach of Sections 7 or 8 of this Agreement, and the Executive expressly consents to the non-exclusive jurisdiction of the district courts of the State of Texas for any such claims. Claims covered by this agreement to arbitrate also include claims by theExecutive for breach of this Agreement, wrongful termination, discrimination (based on age, race, sex, disability, national origin or any other factor) andretaliation. In the event of any breach of this Agreement by the Company, it is expressly agreed that notwithstanding any other provision of this Agreement, theonly damages to which the Executive shall be entitled is lost compensation and benefits in accordance with Section 2(b) or 4. The Company and the Executiveagree that any arbitration shall be in accordance with the Federal Arbitration Act (“FAA”) and, to the extent an issue is not addressed by the FAA, with thethen-current National Rules for the Resolution of Employment Disputes of the American Arbitration Association (“AAA”) or such other rules of the AAA asapplicable to the claims being arbitrated. If a party refuses to honor its obligations under this agreement to arbitrate, the other party may compel arbitration ineither federal or state court. The arbitrator shall apply the substantive law of the State of Texas (excluding, to the extent applicable, choice-of-law principlesthat might call for the application of some other state’s law), or federal law, or both as applicable to the claims asserted. The arbitrator shall have exclusiveauthority to resolve any dispute relating to the interpretation, applicability, enforceability or formation of this agreement to arbitrate, including any claim thatall or part of this Agreement is void or voidable and any claim that an issue is not subject to arbitration. The parties agree that venue for arbitration will be inHarris County, Texas, and that any arbitration commenced in any other venue will be transferred to Harris County, Texas, upon the written request of anyparty to this Agreement. In the event that an arbitration is actually conducted pursuant to this Section 10(j), the party in whose favor the arbitrator renders theaward shall be entitled to have and recover from the other party all costs and expenses incurred, including reasonable attorneys’ fees, expert witness fees, andcosts actually incurred. Any and all of the arbitrator’s orders, decisions and awards may be enforceable in, and judgment upon any award rendered by thearbitrator may be confirmed and entered by, any federal or state court having jurisdiction. All proceedings conducted pursuant to this agreement to arbitrate,including any order, decision or award of the arbitrator, shall be kept confidential by all parties. THE EMPLOYEE ACKNOWLEDGES THAT, BYSIGNING THIS AGREEMENT, THE EMPLOYEE IS WAIVING ANY RIGHT THAT THE EMPLOYEE MAY HAVE TO A JURY TRIALOR, EXCEPT AS EXPRESSLY PROVIDED HEREIN, A COURT TRIAL OF ANY EMPLOYMENT-RELATED CLAIM THAT THEEMPLOYEE MAY ALLEGE. (k) Survival. Sections 7, 8 and 9 of this Agreement shall survive the termination of this Agreement. 12 (l) Choice of Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Texas withoutreference to principles of conflict of laws of Texas or any other jurisdiction, and, where applicable, the laws of the United States. (m) Amendment. This Agreement may not be amended or modified at any time except by a written instrument approved by the Boardand executed by the Company and the Executive. (n) Assignment. This Agreement is personal as to the Executive and accordingly, the Executive’s duties may not be assigned by theExecutive. This Agreement may be assigned by the Company without the Executive’s consent to any entity which is a successor in interest to the Company’sbusiness, provided such successor expressly assumes the Company’s obligations hereunder. (o) Executive Acknowledgment. The Executive acknowledges that he has read and understands this Agreement, is fully aware of itslegal effect, has not acted in reliance upon any representatives or promises made by the Company other than those contained in writing herein, and has enteredinto this Agreement freely based on his own judgment. IN WITNESS WHEREOF, the Executive has hereunto set the Executive’s hand and, pursuant to the authorization from the Board, the Companyhas caused this Agreement to be executed in its name on its behalf, all as of the day and year first above written. EXECUTIVE: /s/ Nelson M. HaightNelson M. Haight MIDSTATES PETROLEUM COMPANY, INC.,a Delaware corporation By:/s/ John P. FoleyName:John P. FoleyTitle:Corporate Counsel and Secretary 13 Exhibit A · Acadia Parish· Allen Parish· Ascension Parish· Assumption Parish· Beauregard Parish· Calcasieu Parish· Evangeline Parish· East Baton Rouge Parish· East Feliciana Parish· Iberville Parish· Pointe Coupee Parish· Rapides Parish· West Baton Rouge Parish· West Feliciana Parish· Vernon Parish 14Exhibit 10.11 AMENDMENT TO EXECUTIVE EMPLOYMENT AGREEMENT This Amendment to Executive Employment Agreement (the “Amendment”) is made and entered into as of December 12, 2013 by and betweenMIDSTATES PETROLEUM COMPANY, INC., (the “Company”), and Nelson M. Haight (the “Executive”). Company and Executive previouslyentered into that certain Executive Employment Agreement (the “Original Agreement”) dated April 25, 2012. All capitalized terms used in this Amendmentbut not defined herein shall have the meanings given to such terms in the Original Agreement. In consideration of the respective agreements and covenants set forth in this Amendment, the receipt of which is hereby acknowledged, the partiesintending to be legally bound agree as follows: AGREEMENTS 1. Section 2(a)(1) of the Original Agreement is deleted in its entirety and replaced with the following: (1) Form and after January 6, 2014, during the Term, the Executive shall serve as Senior Vice President, Chief FinancialOfficer and Chief Accounting Officer and, in so doing, shall perform the duties and responsibilities consistent with the position set forth above in a companyof the size and nature of the Company, and such other duties, responsibilities, and authority assigned to the Executive from time to time by the Board ofDirectors of the Company (the “Board”) or such other officer of the company as shall be designated by the Board. 2. Section 2(b)(1) of the Original Agreement is deleted in its entirety and replaced with the following: (1) Base Salary. During the Term, the Executive shall receive an annualized base salary (“Base Salary”), which shall bepaid in accordance with the customary payroll practices of the Company, in an amount equal to $300,000.00. The Board (or a committee of the Board,designated by the Board to make such decisions), in its sole discretion, may at any time adjust (but not decrease below the aforementioned amount) theamount of the Base Salary as it may deem appropriate, and the term “Base Salary,” as used in this Agreement, shall refer to the Base Salary as it may be soadjusted. 3. Section 4(d) of the Original Agreement is deleted in its entirety and replaced with the following: (d) Without Cause; For Good Reason. If the Executive’s employment is terminated by the Company without Cause before expirationof the Term, or if the Executive resigns for Good Reason before expiration of the Term, the Company shall have no further payment obligations to the Executiveor his legal representatives, other than for payment of: (1) in a lump sum in cash within thirty (30) days after the Date of Termination (or such earlier date asrequired by applicable law) the Accrued Obligations; (2) the Accrued Incentives, which shall be payable in accordance with the terms and conditions of theIncentive Plans; (3) subject to Section 4(f) below, a lump-sum cash payment, to be made on the first normal payroll date 1 following the Release Consideration Period (the “Initial Severance Payment Date”) in an amount equal to (x) the average of the annual bonuses paid to theExecutive for the three immediately preceding completed fiscal years, or (y) if upon the Date of Termination the Executive has not been employed for threecomplete fiscal years, then the average of the annual bonuses paid to the Executive for the years employed with the Company (the “Average Bonus”); and(4) subject to Section 4(f) below, beginning on the Initial Severance Payment Date and thereafter in accordance with the customary payroll practices of theCompany, continuation of the Executive’s Base Salary in effect on the Date of Termination (“Salary Continuation Payments”) for a period of 18 months. Any installments of the Severance Payments that, in accordance with customary payroll practices, would have typically been made during the ReleaseConsideration Period shall accumulate and shall then be paid on the Initial Severance Payment Date. The Average Bonus together with the Salary ContinuationPayments shall be referred to collectively as the “Severance Payments”. 4. Miscellaneous. (a) Effect of Amendment. Except as expressly amended or modified herein, all other terms, covenants, and conditions of the OriginalAgreement shall be unaffected by this Amendment and shall remain in full force and effect. In the event of conflict between the provisions of this Amendmentand the provisions of the Original Agreement, this Amendment shall control. (b) Counterparts. This Amendment may be executed in any number of counterparts, each of which shall be deemed an original andeach of which alone, and all of which together, shall constitute one and the same instrument. (c) Executive Acknowledgment. The Executive acknowledges that he has read and understands this Amendment, is fully aware ofits legal effect, has not acted in reliance upon any representatives or promises made by the Company other than those contained in writing herein, and hasentered into this Amendment freely based on his own judgment. [Signature page follows.] 2 IN WITNESS WHEREOF, the Executive has hereunto set the Executive’s hand and, pursuant to the authorization from the Board, the Companyhas caused this Amendment to be executed in its name on its behalf, all as of the day and year first above written. EXECUTIVE: /s/ Nelson M. HaightNelson M. Haight MIDSTATES PETROLEUM COMPANY, INC.,a Delaware corporation By:/s/ John A CrumName:John A. CrumTitle:President and Chief Executive Officer 3Exhibit 10.12 EXECUTIVE EMPLOYMENT AGREEMENT This Executive Employment Agreement (the “Agreement”) is made and entered into as of April 25, 2012 (the “Effective Date) by and betweenMIDSTATES PETROLEUM COMPANY, INC., (the “Company”), and Curtis A. Newstrom (the “Executive”). In consideration of the respective agreements and covenants set forth in this Agreement, the receipt of which is hereby acknowledged, the partiesintending to be legally bound agree as follows: AGREEMENTS 1. Term. The Company agrees to employ Executive, and Executive agrees to be employed by the Company, upon the terms and conditionsset forth in this Agreement for a period (the “Initial Term”) commencing on the Effective Date and ending on the second anniversary of such date, unlessearlier terminated in accordance with Section 3. If neither party gives at least sixty (60) days written notice to the other party that it intends for this Agreementto terminate on such second anniversary, then this Agreement shall continue for successive one year terms (each a “Renewal Term”), unless earlier terminatedin accordance with Section 3, until either party gives at least sixty (60) days written notice to the other party that the other party intends for this Agreement toterminate at the end of any such one year period. The Initial Term and any Renewal Terms shall, together, constitute the “Term”. 2. Terms of Employment. (a) Position and Duties. (1) During Term, the Executive shall serve as Vice President of Business Development and, in so doing, shall perform theduties and responsibilities consistent with the position set forth above in a company of the size and nature of the Company, and such other duties,responsibilities, and authority assigned to the Executive from time to time by the Board of Directors of the Company (the “Board”) or such other officer of thecompany as shall be designated by the Board. (2) During the Term, the Executive agrees to devote his full working time to the business and affairs of the Company and touse his best efforts to perform faithfully, effectively and efficiently his duties. The Executive covenants, warrants and represents that he shall: (i) devote hisfull and best efforts to the fulfillment of his employment obligations; (ii) exercise the highest degree of fiduciary loyalty and care and the highest standards ofconduct in the performance of his duties; and (iii) endeavor to prevent any harm, in any way, to the business or reputation of the Company or its affiliates. (b) Compensation. (1) Base Salary. During the Term, the Executive shall receive an annualized base salary (“Base Salary”), which shall bepaid in accordance with the customary payroll practices of the Company, in an amount equal to $275,000.00. The Board (or a committee of the Board,designated by the Board to make such decisions), in its sole discretion, 1 may at any time adjust (but not decrease below the aforementioned amount) the amount of the Base Salary as it may deem appropriate, and the term “BaseSalary,” as used in this Agreement, shall refer to the Base Salary as it may be so adjusted. (2) Bonus, Incentive, Savings, Profit Sharing and Retirement Plans. During the Term, and subject to the terms andconditions of applicable plans or programs, the Executive shall be eligible to participate in all bonus, incentive, savings, profit sharing and retirement plans,practices, policies and programs applicable generally to other similarly situated employees of the Company, as adopted or amended from time to time (“Incentive Plans”). The Company may in its sole discretion, from time to time, award the Executive bonus, incentive or other compensation under suchIncentive Plans in such amounts and at such times as the Board determines. (3) Welfare Benefit Plans. During the Term, and subject to the terms and conditions of applicable plans or programs, theExecutive and/or the Executive’s family, as the case may be, shall be eligible for participation in and shall receive all benefits under the welfare benefit plans,practices, policies and programs applicable generally to other similarly situated employees of the Company (which may include programs such as salarycontinuance, medical, prescription, dental, disability, employee life, group life, accidental death and travel accident insurance plans and programs), asadopted or amended from time to time (“Welfare Plans”). (4) Perquisites. During the Term, the Executive shall be entitled to receive (in addition to the benefits described above)such perquisites and fringe benefits appertaining to his position in accordance with any policies, practices, and procedures established by the Board, asamended from time to time. (5) Expenses. Executive is authorized to incur reasonable business expenses that, in Executive’s reasonable businessjudgment, are necessary to carry out his duties for the Company under this Agreement. Executive shall be entitled to reimbursement for such expenses, inaccordance with the Company’s standard procedures and policies, for all reasonable travel, entertainment and other expenses incurred in connection with theCompany’s business and the performance of his duties hereunder. (6) Vacation. During the Term, the Executive shall be entitled to four (4) weeks of paid vacation each calendar year,subject to the Company’s standard carryover policy. 3. Termination of Employment. (a) Death or Disability. The Executive’s employment shall terminate automatically upon the Executive’s death during the Term. Ifthe Disability of the Executive has occurred during the Term (pursuant to the definition of Disability set forth below), the Company may give to the Executivewritten notice in accordance with Section 10(c) of its intention to terminate the Executive’s employment. In such event, the Executive’s employment with theCompany shall terminate effective on the 30th day after receipt of such notice by the Executive (the “Disability Effective Date”), provided that, within the 30days after such receipt, the 2 Executive shall not have returned to perform, with or without reasonable accommodation, the essential functions of his position. For purposes of thisAgreement, “Disability” shall mean the Executive’s inability to engage in any substantial gainful activity by reason of any medically determinable physical ormental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months. (b) Cause. The Company may terminate the Executive’s employment at any time during the Term for Cause or without Cause. Forpurposes of this Agreement, “Cause” shall mean (1) a breach by the Executive of the Executive’s obligations under Section 2(a) (other than as a result ofphysical or mental incapacity) which constitutes nonperformance by the Executive of his obligations and duties thereunder, as determined by the Board(which may, in its sole discretion, give the Executive notice of, and the opportunity to remedy, such breach), (2) commission by the Executive of an act offraud, embezzlement, misappropriation, willful misconduct or breach of fiduciary duty against the Company or other conduct harmful or potentially harmfulto the Company’s best interest, as reasonably determined by a majority of the members of the Board after a hearing by the Board following ten (10) days’notice to the Executive of such hearing, (3) a material breach by the Executive of Sections 7 or 8 of this Agreement, (4) the Executive’s conviction, plea of nocontest or nolo contendere, deferred adjudication or unadjudicated probation for any felony or any crime involving fraud, dishonesty, or moral turpitude orcausing material harm, financial or otherwise, to the Company, (5) the refusal or failure of the Executive to carry out, or comply with, in any material respect,any lawful directive of the Board (which the Board, in its sole discretion, may give the Executive notice of, and an opportunity to remedy), (6) the Executive’sunlawful use (including being under the influence) or possession of illegal drugs; or (7) the Executive’s willful violation of any federal, state, or local law orregulation applicable to the Company or its business which adversely affects the Company. For purposes of the previous sentence, no act or failure to act onthe Executive’s part shall be deemed “willful” unless done, or omitted to be done, by the Executive not in good faith and without reasonable belief that theExecutive’s action or omission was in the best interest of the Company. The Company may suspend the Executive’s title and authority pending the hearingprovided for above. For purposes of this Agreement, a termination “without Cause” shall mean a termination by the Company of the Executive’semployment during the Term at the Company’s sole discretion for any reason other than a termination based upon Cause, death or Disability; provided that atermination “without Cause” does not include the expiration of the Term pursuant to Section 1. (c) Good Reason. The Executive’s employment may be terminated during the Term by the Executive for Good Reason or withoutGood Reason; provided, however, that the Executive agrees not to terminate his employment for Good Reason unless (x) the Executive has given the Companyat least 30 days prior written notice of his intent to terminate his employment for Good Reason, which notice shall specify the facts and circumstancesconstituting Good Reason, (y) the Company has not remedied such facts and circumstances constituting Good Reason within such 30-day period, and (z) theExecutive separates from service on or before the 60 day after the end of the 30-day cure period enumerated in the immediately preceding clause (y). Forpurposes of this Agreement, “Good Reason” shall mean any of the following, but only if occurring without the Executive’s consent: (1) a material diminutionin the Executive’s Base Salary, (2) a material diminution in the Executive’s authority, duties, or responsibilities, (3) the relocation of the Executive’s principaloffice to an area more than 50 miles from its location 3th immediately prior to such relocation, or (4) the failure of the Company to comply with any material provision of this Agreement. Such termination by theExecutive shall not preclude the Company from terminating the Executive’s employment prior to the Date of Termination (as defined below) established by theExecutive’s Notice of Termination (as defined below). (d) Notice of Termination. Any termination by the Company for Cause or without Cause or because of the Executive’s Disability, orby the Executive for Good Reason or without Good Reason, shall be communicated by Notice of Termination to the other party hereto given in accordance withSection 10(c). For purposes of this Agreement, a “Notice of Termination” means a written notice which (1) indicates the specific termination provision in thisAgreement relied upon, (2) to the extent applicable, sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of theExecutive’s employment under the provision so indicated and (3) if the Date of Termination (as defined below) is other than the date of receipt of such notice,specifies the termination date (which date shall not be more than 30 days after the giving of such notice). The failure by the Company or the Executive to setforth in the Notice of Termination any fact or circumstance which contributes to a showing of Cause or Good Reason, as applicable shall not waive any rightof the Company or the Executive under this Agreement or preclude the Company or the Executive from asserting such fact or circumstance in enforcing theCompany’s or Executive’s rights under this Agreement. (e) Date of Termination. “Date of Termination” means (1) if the Executive’s employment is terminated by the Company for Causeor without Cause, or by the Executive for Good Reason or without Good Reason, the date of receipt of the Notice of Termination or any later date specifiedtherein pursuant to Section 3(d), as the case may be, provided that if such date is not also the date of Executive’s “Separation from Service” with theCompany (within the meaning of Treasury Regulation 1.409A-1(h)) then the “Date of Termination” shall instead be the date of the Executive’s Separation fromService, or (2) if the Executive’s employment is terminated by reason of death or Disability, the date of death of the Executive or the Disability Effective Date,as the case may be. 4. Obligations of the Company upon Termination. (a) For Cause; Without Good Reason; Other Than for Death or Disability. If, during the Term, the Company shall terminate theExecutive’s employment for Cause or the Executive resigns from his employment without Good Reason, and the termination of the Executive’s employment inany case is not due to his death or Disability, or the Company shall have no further payment obligations to the Executive or his legal representatives, other thanfor the payment of: (1) in a lump sum in cash within thirty (30) days after the Date of Termination (or such earlier date as required by applicable law) thatportion of the Executive’s Annual Base Salary accrued through the Date of Termination to the extent not previously paid, any expense reimbursement accruedand unpaid, any employee benefits pursuant to the terms of the applicable employee benefit plan, and any accrued but unused vacation (the “AccruedObligations”); and (2) any accrued or vested amount arising from the Executive’s participation in, or benefits under, any Incentive Plans (the “AccruedIncentives”), which amounts shall be payable in accordance with the terms and conditions of such Incentive Plans. 4 (b) Death. If the Executive’s employment is terminated by reason of the Executive’s death during the Term, the Company shall haveno further payment obligations to the Executive or Executive’s legal representatives, other than for payment of: (1) a lump sum in cash within thirty (30) daysafter the Date of Termination (or such earlier date as required by applicable law) the Accrued Obligations; and (2) the Accrued Incentives, which shall bepayable in accordance with the terms and conditions of the Incentive Plans. (c) Disability. If the Executive’s employment is terminated by reason of the Executive’s Disability during the Term, the Companyshall have no further payment obligations to the Executive or his legal representatives, other than for payment of: (1) a lump sum in cash within thirty (30)days after the Date of Termination (or such earlier date as required by applicable law) the Accrued Obligations; and (2) the Accrued Incentives, which shall bepayable in accordance with the terms and conditions of the Incentive Plans. (d) Without Cause; For Good Reason. If the Executive’s employment is terminated by the Company without Cause before expirationof the Term, or if the Executive resigns for Good Reason before expiration of the Term, the Company shall have no further payment obligations to the Executiveor his legal representatives, other than for payment of: (1) in a lump sum in cash within thirty (30) days after the Date of Termination (or such earlier date asrequired by applicable law) the Accrued Obligations; (2) the Accrued Incentives, which shall be payable in accordance with the terms and conditions of theIncentive Plans; (3) subject to Section 4(f) below, a lump-sum cash payment, to be made on the first normal payroll date following the Release ConsiderationPeriod (the “Initial Severance Payment Date”) in an amount equal to (x) the average of the annual bonuses paid to the Executive for the three immediatelypreceding completed fiscal years, or (y) if upon the Date of Termination the Executive has not been employed for three complete fiscal years, then the average ofthe annual bonuses paid to the Executive for the years employed with the Company (the “Average Bonus”); and (4) subject to Section 4(f) below, beginningon the Initial Severance Payment Date and thereafter in accordance with the customary payroll practices of the Company, continuation of the Executive’s BaseSalary in effect on the Date of Termination (“Salary Continuation Payments”) for a period of 12 months. Any installments of the Severance Paymentsthat, in accordance with customary payroll practices, would have typically been made during the Release Consideration Period shall accumulate and shall thenbe paid on the Initial Severance Payment Date. The Average Bonus together with the Salary Continuation Payments shall be referred to collectively as the“Severance Payments”. (e) Protected Period: Without Cause; For Good Reason. If the Executive’s employment is terminated by the Company without Causebefore expiration of the Term, or if the Executive resigns for Good Reason before expiration of the Term, in each case, at any time during the Protected Period(as defined below), the Company shall have no further payment obligations to the Executive or his legal representatives, other than: (1) payment in a lump-sum in cash within thirty (30) days after the Date of Termination (or such earlier date as required by applicable law) the Accrued Obligations; (2) payment ofthe Accrued Incentives, which shall be payable in accordance with the terms and conditions of the Incentive Plans; (3) Subject to Section 4(f) below, on theInitial Severance Payment Date, all unvested awards granted to the Executive under the Midstates Petroleum Company, Inc. 2012 Long Term Incentive Plan(the “LTIP”) shall vest, except for (x) any annual cash bonuses granted under the LTIP, and (y) any 5 awards granted under Section 8 of the LTIP or otherwise intended to qualify as “qualified performance-based compensation” under Section 162(m) of theInternal Revenue Code (the “Code”) and any regulations or guidance promulgated thereunder; and (4) Subject to Section 4(f) below, on the Initial SeverancePayment Date, payment of a lump sum cash payment equal to the product of 2 multiplied by the sum of (x) the highest Base Salary paid to the Executiveduring the three years immediately preceding the Change in Control and (y) the highest annual bonus paid to the Executive for the three completed fiscal yearsimmediately preceding the Change in Control (the accelerated vesting enumerated in clause (3) of this Section 4(e), together with the payments enumerated inthis clause (4) of this Section 4(e), collectively the “CIC Severance Payments”). “Protected Period” means the period beginning on the date of a Change inControl (as defined below) and continuing until the one-year anniversary of such Change in Control. “Change in Control” shall have the meaning set forth inthe LTIP. (f) Release and Compliance with this Agreement. The obligation of the Company to pay any portion of the amounts due pursuant toSection 4, with the exception of Accrued Obligations and Accrued Incentives, shall be expressly conditioned on the Executive’s (1) execution (and, ifapplicable, non-revocation) of a full general release, releasing all claims, known or unknown, that the Executive may have against the Company, includingthose arising out of or in any way related to the Executive’s employment or termination of employment with the Company no later than the 60 day followingthe Date of Termination (such period, the “Release Consideration Period”) and (2) continued compliance with the requirements of Sections 7 and 8. (g) Section 409A. Other than the Severance Payments, the amounts payable pursuant to Section 4 of this Plan are intended tocomply with the short-term deferral exception to Section 409A of the Code. To the extent that a Participant is a “specified employee” within the meaning of theTreasury Regulations issued pursuant to Section 409A of the Code as of the Participant’s Date of Termination, no amount that constitutes a deferral ofcompensation which is payable on account of the Participant’s separation from service shall be paid to the Participant before the date (the “Delayed PaymentDate”) which is first day of the seventh month after the Participant’s Date of Termination or, if earlier, the date of the Participant’s death following such Dateof Termination. All such amounts that would, but for this Section 4(g), become payable prior to the Delayed Payment Date will be accumulated and paid onthe Delayed Payment Date. No interest will be paid by the Company with respect to any such delayed payments. For purposes of Section 409A of the Code,each payment or amount due under this Plan shall be considered a separate payment, and a Participant’s entitlement to a series of payments under this Plan isto be treated as an entitlement to a series of separate payments. 5. Excise Taxes. If the Board determines, in its sole discretion, that Section 280G of the Code applies to any compensation payable to theExecutive, then the provisions of this Section 5 shall apply. If any payments or benefits to which the Executive is entitled from the Company, any affiliate,any successor to the Company or an affiliate, or any trusts established by any of the foregoing by reason of, or in connection with, any transaction thatoccurs after the Effective Date (collectively, the “Payments,” which shall include, without limitation, the vesting of any equity awards or other non-cashbenefit or property) are, alone or in the aggregate, more likely than not, if paid or delivered to the Executive, to be subject to the tax imposed by Section 4999of the Code or any successor provisions to that section, then the Payments (beginning with 6th any Payment to be paid in cash hereunder), shall be either (a) reduced (but not below zero) so that the present value of such total Payments received by theExecutive will be one dollar ($1.00) less than three times the Executive’s “base amount” (as defined in Section 280G(b)(3) of the Code) and so that no portionof such Payments received by the Executive shall be subject to the excise tax imposed by Section 4999 of the Code, or (b) paid in full, whichever of (a) or(b) produces the better net after tax position to the Executive (taking into account any applicable excise tax under Section 4999 of the Code and any otherapplicable taxes). The determination as to whether any Payments are more likely than not to be subject to taxes under Section 4999 of the Code and as towhether reduction or payment in full of the amount of the Payments provided hereunder results in the better net after tax position to the Executive shall be madeby the Board and the Executive in good faith. 6. Full Settlement. Neither the Executive nor the Company shall be liable to the other party for any damages for breach of this Agreement inaddition to the amounts payable under Section 4 arising out of the termination of the Executive’s employment prior to the end of the Term; provided, however,that the Company shall be entitled to seek damages from the Executive for any breach of Sections 7 or 8 by the Executive or for the Executive’s criminalmisconduct. 7. Confidential Information. (a) The Executive acknowledges that the Company has trade, business and financial secrets and other confidential and proprietaryinformation (collectively, the “Confidential Information”) which shall be provided to the Executive during the Executive’s employment by the Company. Confidential information includes, but is not limited to, sales materials, technical information, strategic information, business plans, processes andcompilations of information, records, specifications and information concerning customers or venders, customer lists, and information regarding methods ofdoing business. (b) The Executive is aware of those policies implemented by the Company to keep its Confidential Information secret, includingthose policies limiting the disclosure of information on a need-to-know basis, requiring the labeling of documents as “confidential,” and requiring the keepingof information in secure areas. The Executive acknowledges that the Confidential Information has been developed or acquired by the Company through theexpenditure of substantial time, effort and money and provides the Company with an advantage over competitors who do not know or use such ConfidentialInformation. The Executive acknowledges that all such Confidential Information is the sole and exclusive property of the Company. (c) During, and all times following, the Executive’s employment by the Company, the Executive shall hold in confidence and notdirectly or indirectly disclose or use or copy or make lists of any Confidential Information: except (i) to the extent authorized in writing by the Board; (ii) wheresuch information is, at the time of disclosure by the Executive, generally available to the public other than as a result of any direct or indirect act or omissionof the Executive in breach of this Agreement; or (iii) where the Executive is compelled by legal process, other than to an employee of the Company or a personto whom disclosure is reasonably 7 necessary or appropriate in connection with the performance by the Executive of his duties as an employee of the Company. The Executive agrees to usereasonable efforts to give the Company notice of any and all attempts to compel disclosure of any Confidential Information, in such a manner so as to providethe Company with written notice at least five (5) days before disclosure or within one (1) business day after the Executive is informed that such disclosure isbeing or will be compelled, whichever is earlier. Such written notice shall include a description of the information to be disclosed, the court, governmentagency, or other forum through which the disclosure is sought, and the date by which the information is to be disclosed, and shall contain a copy of thesubpoena, order or other process used to compel disclosure. (d) The Executive will take all necessary precautions to prevent disclosure to any unauthorized individual or entity. The Executivefurther agrees not to use, whether directly or indirectly, any Confidential Information for the benefit of any person, business, corporation, partnership, or anyother entity other than the Company. (e) As used in this Section 7, “Company” shall include Midstates Petroleum Company, Inc. and any of its affiliates. 8. Non-Competition; Non-Solicitation. (a) The Executive acknowledges and agrees that the nature of the Confidential Information which the Company commits to providehim during his employment by the Company would make it difficult, if not impossible, for him to perform in a similar capacity for a Competing Business(as defined below) without disclosing or utilizing the Confidential Information. Further, the Executive acknowledges that the Company shall, during the timethat the Executive is employed by Company, (a) disclose or entrust to the Executive, and provide the Executive access to, or place the Executive in a position tocreate or develop, trade secrets or Confidential Information belonging to the Company, (b) place the Executive in a position to develop business goodwillbelonging to the Company, and (c) disclose or entrust to the Executive business opportunities to be developed for the Company. Accordingly, in considerationof the foregoing, the Executive agrees that he will not (other than for the benefit of the Company pursuant to this Agreement) directly or indirectly, individuallyor on behalf of any other person, firm, corporation or other entity (whether as an officer, director, employee, shareholder, consultant, contractor, partner, jointventurer, agent, equity owner or in any capacity whatsoever) (1) during the term of Non-Competition (as defined below), carry on or engage in the business ofdeveloping and/or implementing drilling and completion techniques to oil-prone resources in previously discovered yet underdeveloped hydrocarbon trends orin any other business activity that the Company is conducting, or is intending to conduct, on the Date of Termination, in each case in the parishes within theState of Louisiana listed in Exhibit A to this Agreement, the State of Texas, and any other geographical area in which the Company conducts business and, asof the Date of Termination, was planning to conduct business and to which the Executive’s duties as an employee of the Company related (a “CompetingBusiness”), or (2) during the Term of Non-Solicitation (as defined below), (i) hire, attempt to hire, or contact or solicit with respect to hiring any employee,officer, or consultant of the Company, or (ii) solicit, divert or take away any customers, customer leads, or suppliers (as of the Date of Termination) of theCompany. The “Term of Non-Competition” and the “Term of Non-Solicitation” shall be defined as that term beginning on the Effective Date andcontinuing until (x) if the 8 Executive’s employment is terminated by reason of death or Disability, the Date of Termination, or (y) if the Executive’s employment is terminated by theCompany for Cause or without Cause, or by the Executive for Good Reason or without Good Reason, the date that is the one year anniversary of the Date ofTermination. (b) Notwithstanding the restrictions contained in Section 8(a), the Executive or any of the Executive’s affiliates may own an aggregateof not more than 2.0% of the outstanding stock of any class of a Competing Business, if such stock is listed on a national securities exchange or regularlytraded in the over-the-counter market by a member of a national securities exchange, without violating the provisions of Section 8(a), provided that neither theExecutive nor any of the Executive’s affiliates has the power, directly or indirectly, to control or direct the management or affairs of any such corporation andis not involved in the management of such corporation. (c) The Executive acknowledges that the geographic boundaries, scope of prohibited activities, and time duration of the precedingparagraphs are reasonable in nature and are no broader than are necessary to maintain the confidentiality and the goodwill of the Company and theconfidentiality of its Confidential Information and to protect the other legitimate business interests of the Company. The Executive further represents andacknowledges that (i) he or she has been advised by the Company to consult his or her own legal counsel in respect of this Agreement, and (ii) that he or shehas had full opportunity, prior to executing this Agreement, to review thoroughly this Agreement with his or her counsel. (d) If any court determines that any portion of this Section 8 is invalid or unenforceable, the remainder of this Section 8 shall notthereby be affected and shall be given full effect without regard to the invalid provisions. If any court construes any of the provisions of this Section 8, or anypart thereof, to be unreasonable because of the duration or scope of such provision, such court shall have the power to reduce the duration or scope of suchprovision and to enforce such provision as so reduced. (e) The Executive’s covenant under this Section 8 of the Agreement shall be construed as an agreement independent of any otherprovision of this Agreement; and the existence of any claim or cause of action of Executive against the Company, whether predicated on this Agreement orotherwise, shall not constitute a defense to the enforcement by the Company of this covenant. (f) As used in this Section 8, “Company” shall include Midstates Petroleum Company, Inc. and any of its affiliates. 9. Mutual Non-Disparagement. The Executive agrees not to intentionally make, or intentionally cause any other Person to make, anypublic statement that is intended to criticize or disparage the Company, any of its affiliates, or any of their respective officers, managers or directors. TheCompany agrees to use commercially reasonable efforts to cause its officers and members of its Board not to intentionally make, or intentionally cause anyother Person t make, any public statement that is intended to criticize or disparage the Executive. This Section 9 shall not be construed to prohibit any personfrom responding publicly to incorrect public statements or from making truthful statements when required by law, subpoena, court order, or the like. 9 10. Miscellaneous. (a) Survival and Construction. Executive’s obligations under this Agreement will be binding upon Executive’s heirs, executors,assigns, and administrators and will inure to the benefit of the Company, its subsidiaries, successors, and assigns. The language of this Agreement shall inall cases be construed as a whole according to its fair meaning, and not strictly for or against any of the parties. The section and paragraph headings used inthis Agreement are intended solely for the convenience of reference and shall not in any manner amplify, limit, modify, or otherwise be used in theinterpretation of any of the provisions hereof. (b) Definitions. As used in this Agreement, “affiliate” means, with respect to a person, any other person controlling, controlled byor under common control with the first person; the term “control,” and correlative terms, means the power, whether by contract, equity ownership orotherwise, to direct the policies or management of a person; and “person” means an individual, partnership, corporation, limited liability company, trust orunincorporated organization, or a government or agency or political subdivision thereof. (c) Notices. All notices and other communications hereunder shall be in writing and shall be given by hand delivery to the otherparty or by registered or certified mail, return receipt requested, postage prepaid, addressed as follows: If to the Executive:Curtis A. Newstrom13406 Keyridge Ln.Cypress, Texas 77429 If to the Company:Attn: Vice President of Human ResourcesMidstates Petroleum Company, Inc.4400 Post Oak Parkway, Suite 1900Houston, Texas 77027(713) 595-9400 or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notice and communications shall be effective whenactually received by the addressee. (d) Enforcement. If any provision of this Agreement is held to be illegal, invalid or unenforceable under present or future lawseffective during the term of this Agreement, such provision shall be fully severable; this Agreement shall be construed and enforced as if such illegal, invalidor unenforceable provision had never comprised a portion of this Agreement; and the remaining provisions of this Agreement shall remain in full force andeffect and shall not be affected by the illegal, invalid or unenforceable provision or by its severance from this Agreement. Furthermore, in lieu of such illegal,invalid or unenforceable provision there shall be added automatically as part of this Agreement a provision as similar in 10 terms to such illegal, invalid or unenforceable provision as may be possible and be legal, valid and enforceable. (e) Withholding. The Company may withhold from any amounts payable under this Agreement such Federal, state or local taxes asshall be required to be withheld pursuant to any applicable law or regulation as determined by the Company. (f) Section 409A Compliance. This Agreement is intended to comply with (or be exempt from) Code Section 409A and theprovisions of this Agreement shall be construed accordingly. To the extent that any in-kind benefits or reimbursements pursuant to this Agreement are taxableto Executive and constitute deferred compensation subject to Section 409A of the Code, any reimbursement payment due to Executive shall be paid toExecutive on or before the last day of the Executive’s taxable year following the taxable year in which the related expense was incurred. In addition, any suchin-kind benefit or reimbursement is not subject to liquidation or exchange for another benefit and the amount of such benefit or reimbursement that Executivereceives in one taxable year shall not affect the amount of such benefit and reimbursements that Executive receives in any other taxable year. The Executiveagrees to promptly submit and document any reimbursable expenses in accordance with the Company’s reasonable expense reimbursement policies to facilitatethe timely reimbursement of such expenses. (g) No Waiver. No waiver by either party at any time of any breach by the other party of, or compliance with, any condition orprovision of this Agreement to be performed by the other party shall be deemed a waiver of similar or dissimilar provisions or conditions at any time. (h) Equitable and Other Relief. The Executive acknowledges that money damages would be both incalculable and an insufficientremedy for a breach of Sections 7 or 8 by the Executive and that any such breach would cause the Company irreparable harm. Accordingly, the Company, inaddition to any other remedies at law or in equity it may have, shall be entitled, without the requirement of posting of bond or other security, to equitable relief,including injunctive relief and specific performance, in connection with a breach of Sections 7 or 8 by the Executive. In addition to the remedies the Companymay have at law or in equity, violation of Sections 7 or 8 herein will entitle the Company at its sole option not to pay the Average Bonus or the CIC SeverancePayments, to discontinue the Salary Continuation Payments to the Executive, and to seek repayment from the Executive of any Severance Payments or CICSeverance Payments already paid to him by the Company. Such remedies shall not be deemed to be liquidated damages and shall not be deemed the exclusiveremedies for a breach of this Section 7 or 8 but shall be in addition to all remedies available, at law or in equity, including the recovery of damages from theExecutive and his agents. No action taken by the Company under this Section 10(h) shall affect the enforceability of the release and waiver of claims executedby the Executive pursuant to Section 4(f)4(d). (i) Complete Agreement. The provisions of this Agreement constitute the entire and complete understanding and agreement betweenthe parties with respect to the subject matter hereof, and supersedes all prior and contemporaneous oral and written agreements, representations andunderstandings of the parties, which are hereby terminated. Other than 11 expressly set forth herein, the Executive and Company acknowledge and represent that there are no other promises, terms, conditions or representations (orwritten) regarding any matter relevant hereto. This Agreement may be executed in two or more counterparts. (j) Arbitration. The Company and the Executive agree to the resolution by binding arbitration of all claims, demands, causes ofaction, disputes, controversies or other matters in question (“claims”), whether or not arising out of this Agreement or the Executive’s employment (or itstermination), whether sounding in contract, tort or otherwise and whether provided by statute or common law, that the Company may have against theExecutive or that the Executive may have against the Company or its parents, subsidiaries and affiliates, and each of the foregoing entities’ respective officers,directors, employees or agents in their capacity as such or otherwise; except that this agreement to arbitrate shall not limit the Company’s right to seek equitablerelief, including injunctive relief and specific performance, and damages and any other remedy or relief (including the recovery of attorney fees, costs andexpenses) in a court of competent jurisdiction for an alleged breach of Sections 7 or 8 of this Agreement, and the Executive expressly consents to the non-exclusive jurisdiction of the district courts of the State of Texas for any such claims. Claims covered by this agreement to arbitrate also include claims by theExecutive for breach of this Agreement, wrongful termination, discrimination (based on age, race, sex, disability, national origin or any other factor) andretaliation. In the event of any breach of this Agreement by the Company, it is expressly agreed that notwithstanding any other provision of this Agreement, theonly damages to which the Executive shall be entitled is lost compensation and benefits in accordance with Section 2(b) or 4. The Company and the Executiveagree that any arbitration shall be in accordance with the Federal Arbitration Act (“FAA”) and, to the extent an issue is not addressed by the FAA, with thethen-current National Rules for the Resolution of Employment Disputes of the American Arbitration Association (“AAA”) or such other rules of the AAA asapplicable to the claims being arbitrated. If a party refuses to honor its obligations under this agreement to arbitrate, the other party may compel arbitration ineither federal or state court. The arbitrator shall apply the substantive law of the State of Texas (excluding, to the extent applicable, choice-of-law principlesthat might call for the application of some other state’s law), or federal law, or both as applicable to the claims asserted. The arbitrator shall have exclusiveauthority to resolve any dispute relating to the interpretation, applicability, enforceability or formation of this agreement to arbitrate, including any claim thatall or part of this Agreement is void or voidable and any claim that an issue is not subject to arbitration. The parties agree that venue for arbitration will be inHarris County, Texas, and that any arbitration commenced in any other venue will be transferred to Harris County, Texas, upon the written request of anyparty to this Agreement. In the event that an arbitration is actually conducted pursuant to this Section 10(j), the party in whose favor the arbitrator renders theaward shall be entitled to have and recover from the other party all costs and expenses incurred, including reasonable attorneys’ fees, expert witness fees, andcosts actually incurred. Any and all of the arbitrator’s orders, decisions and awards may be enforceable in, and judgment upon any award rendered by thearbitrator may be confirmed and entered by, any federal or state court having jurisdiction. All proceedings conducted pursuant to this agreement to arbitrate,including any order, decision or award of the arbitrator, shall be kept confidential by all parties. THE EMPLOYEE ACKNOWLEDGES THAT, BYSIGNING THIS AGREEMENT, THE EMPLOYEE IS WAIVING ANY RIGHT THAT THE EMPLOYEE MAY HAVE TO A JURY TRIALOR, EXCEPT AS EXPRESSLY 12 PROVIDED HEREIN, A COURT TRIAL OF ANY EMPLOYMENT-RELATED CLAIM THAT THE EMPLOYEE MAY ALLEGE. (k) Survival. Sections 7, 8 and 9 of this Agreement shall survive the termination of this Agreement. (l) Choice of Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Texas withoutreference to principles of conflict of laws of Texas or any other jurisdiction, and, where applicable, the laws of the United States. (m) Amendment. This Agreement may not be amended or modified at any time except by a written instrument approved by the Boardand executed by the Company and the Executive. (n) Assignment. This Agreement is personal as to the Executive and accordingly, the Executive’s duties may not be assigned by theExecutive. This Agreement may be assigned by the Company without the Executive’s consent to any entity which is a successor in interest to the Company’sbusiness, provided such successor expressly assumes the Company’s obligations hereunder. (o) Executive Acknowledgment. The Executive acknowledges that he has read and understands this Agreement, is fully aware of itslegal effect, has not acted in reliance upon any representatives or promises made by the Company other than those contained in writing herein, and has enteredinto this Agreement freely based on his own judgment. IN WITNESS WHEREOF, the Executive has hereunto set the Executive’s hand and, pursuant to the authorization from the Board, the Companyhas caused this Agreement to be executed in its name on its behalf, all as of the day and year first above written. EXECUTIVE: /s/ Curtis A. NewstromCurtis A. Newstrom MIDSTATES PETROLEUM COMPANY, INC.,a Delaware corporation By:/s/ John P. FoleyName:John P. FoleyTitle:Corporate Counsel and Secretary 13 Exhibit A · Acadia Parish· Allen Parish· Ascension Parish· Assumption Parish· Beauregard Parish· Calcasieu Parish· Evangeline Parish· East Baton Rouge Parish· East Feliciana Parish· Iberville Parish· Pointe Coupee Parish· Rapides Parish· West Baton Rouge Parish· West Feliciana Parish· Vernon Parish 14Exhibit 10.13 EXECUTIVE EMPLOYMENT AGREEMENT This Executive Employment Agreement (the “Agreement”) is made and entered into as of April 25, 2012 (the “Effective Date) by and betweenMIDSTATES PETROLEUM COMPANY, INC., (the “Company”), and Dexter Burleigh (the “Executive”). In consideration of the respective agreements and covenants set forth in this Agreement, the receipt of which is hereby acknowledged, the partiesintending to be legally bound agree as follows: AGREEMENTS 1. Term. The Company agrees to employ Executive, and Executive agrees to be employed by the Company, upon the terms and conditionsset forth in this Agreement for a period (the “Initial Term”) commencing on the Effective Date and ending on the second anniversary of such date, unlessearlier terminated in accordance with Section 3. If neither party gives at least sixty (60) days written notice to the other party that it intends for this Agreementto terminate on such second anniversary, then this Agreement shall continue for successive one year terms (each a “Renewal Term”), unless earlier terminatedin accordance with Section 3, until either party gives at least sixty (60) days written notice to the other party that the other party intends for this Agreement toterminate at the end of any such one year period. The Initial Term and any Renewal Terms shall, together, constitute the “Term”. 2. Terms of Employment. (a) Position and Duties. (1) During Term, the Executive shall serve as Vice President — Strategic Planning and, in so doing, shall perform theduties and responsibilities consistent with the position set forth above in a company of the size and nature of the Company, and such other duties,responsibilities, and authority assigned to the Executive from time to time by the Board of Directors of the Company (the “Board”) or such other officer of thecompany as shall be designated by the Board. (2) During the Term, the Executive agrees to devote his full working time to the business and affairs of the Company and touse his best efforts to perform faithfully, effectively and efficiently his duties. The Executive covenants, warrants and represents that he shall: (i) devote hisfull and best efforts to the fulfillment of his employment obligations; (ii) exercise the highest degree of fiduciary loyalty and care and the highest standards ofconduct in the performance of his duties; and (iii) endeavor to prevent any harm, in any way, to the business or reputation of the Company or its affiliates. (b) Compensation. (1) Base Salary. During the Term, the Executive shall receive an annualized base salary (“Base Salary”), which shall bepaid in accordance with the customary payroll practices of the Company, in an amount equal to $230,000.00. The Board (or a committee of the Board,designated by the Board to make such decisions), in its sole discretion, 1 may at any time adjust (but not decrease below the aforementioned amount) the amount of the Base Salary as it may deem appropriate, and the term “BaseSalary,” as used in this Agreement, shall refer to the Base Salary as it may be so adjusted. (2) Bonus, Incentive, Savings, Profit Sharing and Retirement Plans. During the Term, and subject to the terms andconditions of applicable plans or programs, the Executive shall be eligible to participate in all bonus, incentive, savings, profit sharing and retirement plans,practices, policies and programs applicable generally to other similarly situated employees of the Company, as adopted or amended from time to time (“Incentive Plans”). The Company may in its sole discretion, from time to time, award the Executive bonus, incentive or other compensation under suchIncentive Plans in such amounts and at such times as the Board determines. (3) Welfare Benefit Plans. During the Term, and subject to the terms and conditions of applicable plans or programs, theExecutive and/or the Executive’s family, as the case may be, shall be eligible for participation in and shall receive all benefits under the welfare benefit plans,practices, policies and programs applicable generally to other similarly situated employees of the Company (which may include programs such as salarycontinuance, medical, prescription, dental, disability, employee life, group life, accidental death and travel accident insurance plans and programs), asadopted or amended from time to time (“Welfare Plans”). (4) Perquisites. During the Term, the Executive shall be entitled to receive (in addition to the benefits described above)such perquisites and fringe benefits appertaining to his position in accordance with any policies, practices, and procedures established by the Board, asamended from time to time. (5) Expenses. Executive is authorized to incur reasonable business expenses that, in Executive’s reasonable businessjudgment, are necessary to carry out his duties for the Company under this Agreement. Executive shall be entitled to reimbursement for such expenses, inaccordance with the Company’s standard procedures and policies, for all reasonable travel, entertainment and other expenses incurred in connection with theCompany’s business and the performance of his duties hereunder. (6) Vacation. During the Term, the Executive shall be entitled to four (4) weeks of paid vacation each calendar year,subject to the Company’s standard carryover policy. 3. Termination of Employment. (a) Death or Disability. The Executive’s employment shall terminate automatically upon the Executive’s death during the Term. Ifthe Disability of the Executive has occurred during the Term (pursuant to the definition of Disability set forth below), the Company may give to the Executivewritten notice in accordance with Section 10(c) of its intention to terminate the Executive’s employment. In such event, the Executive’s employment with theCompany shall terminate effective on the 30th day after receipt of such notice by the Executive (the “Disability Effective Date”), provided that, within the 30days after such receipt, the 2 Executive shall not have returned to perform, with or without reasonable accommodation, the essential functions of his position. For purposes of thisAgreement, “Disability” shall mean the Executive’s inability to engage in any substantial gainful activity by reason of any medically determinable physical ormental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months. (b) Cause. The Company may terminate the Executive’s employment at any time during the Term for Cause or without Cause. Forpurposes of this Agreement, “Cause” shall mean (1) a breach by the Executive of the Executive’s obligations under Section 2(a) (other than as a result ofphysical or mental incapacity) which constitutes nonperformance by the Executive of his obligations and duties thereunder, as determined by the Board(which may, in its sole discretion, give the Executive notice of, and the opportunity to remedy, such breach), (2) commission by the Executive of an act offraud, embezzlement, misappropriation, willful misconduct or breach of fiduciary duty against the Company or other conduct harmful or potentially harmfulto the Company’s best interest, as reasonably determined by a majority of the members of the Board after a hearing by the Board following ten (10) days’notice to the Executive of such hearing, (3) a material breach by the Executive of Sections 7 or 8 of this Agreement, (4) the Executive’s conviction, plea of nocontest or nolo contendere, deferred adjudication or unadjudicated probation for any felony or any crime involving fraud, dishonesty, or moral turpitude orcausing material harm, financial or otherwise, to the Company, (5) the refusal or failure of the Executive to carry out, or comply with, in any material respect,any lawful directive of the Board (which the Board, in its sole discretion, may give the Executive notice of, and an opportunity to remedy), (6) the Executive’sunlawful use (including being under the influence) or possession of illegal drugs; or (7) the Executive’s willful violation of any federal, state, or local law orregulation applicable to the Company or its business which adversely affects the Company. For purposes of the previous sentence, no act or failure to act onthe Executive’s part shall be deemed “willful” unless done, or omitted to be done, by the Executive not in good faith and without reasonable belief that theExecutive’s action or omission was in the best interest of the Company. The Company may suspend the Executive’s title and authority pending the hearingprovided for above. For purposes of this Agreement, a termination “without Cause” shall mean a termination by the Company of the Executive’semployment during the Term at the Company’s sole discretion for any reason other than a termination based upon Cause, death or Disability; provided that atermination “without Cause” does not include the expiration of the Term pursuant to Section 1. (c) Good Reason. The Executive’s employment may be terminated during the Term by the Executive for Good Reason or withoutGood Reason; provided, however, that the Executive agrees not to terminate his employment for Good Reason unless (x) the Executive has given the Companyat least 30 days prior written notice of his intent to terminate his employment for Good Reason, which notice shall specify the facts and circumstancesconstituting Good Reason, (y) the Company has not remedied such facts and circumstances constituting Good Reason within such 30-day period, and (z) theExecutive separates from service on or before the 60 day after the end of the 30-day cure period enumerated in the immediately preceding clause (y). Forpurposes of this Agreement, “Good Reason” shall mean any of the following, but only if occurring without the Executive’s consent: (1) a material diminutionin the Executive’s Base Salary, (2) a material diminution in the Executive’s authority, duties, or responsibilities, (3) the relocation of the Executive’s principaloffice to an area more than 50 miles from its location 3th immediately prior to such relocation, or (4) the failure of the Company to comply with any material provision of this Agreement. Such termination by theExecutive shall not preclude the Company from terminating the Executive’s employment prior to the Date of Termination (as defined below) established by theExecutive’s Notice of Termination (as defined below). (d) Notice of Termination. Any termination by the Company for Cause or without Cause or because of the Executive’s Disability, orby the Executive for Good Reason or without Good Reason, shall be communicated by Notice of Termination to the other party hereto given in accordance withSection 10(c). For purposes of this Agreement, a “Notice of Termination” means a written notice which (1) indicates the specific termination provision in thisAgreement relied upon, (2) to the extent applicable, sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of theExecutive’s employment under the provision so indicated and (3) if the Date of Termination (as defined below) is other than the date of receipt of such notice,specifies the termination date (which date shall not be more than 30 days after the giving of such notice). The failure by the Company or the Executive to setforth in the Notice of Termination any fact or circumstance which contributes to a showing of Cause or Good Reason, as applicable shall not waive any rightof the Company or the Executive under this Agreement or preclude the Company or the Executive from asserting such fact or circumstance in enforcing theCompany’s or Executive’s rights under this Agreement. (e) Date of Termination. “Date of Termination” means (1) if the Executive’s employment is terminated by the Company for Causeor without Cause, or by the Executive for Good Reason or without Good Reason, the date of receipt of the Notice of Termination or any later date specifiedtherein pursuant to Section 3(d), as the case may be, provided that if such date is not also the date of Executive’s “Separation from Service” with theCompany (within the meaning of Treasury Regulation 1.409A-1(h)) then the “Date of Termination” shall instead be the date of the Executive’s Separation fromService, or (2) if the Executive’s employment is terminated by reason of death or Disability, the date of death of the Executive or the Disability Effective Date,as the case may be. 4. Obligations of the Company upon Termination. (a) For Cause; Without Good Reason; Other Than for Death or Disability. If, during the Term, the Company shall terminate theExecutive’s employment for Cause or the Executive resigns from his employment without Good Reason, and the termination of the Executive’s employment inany case is not due to his death or Disability, or the Company shall have no further payment obligations to the Executive or his legal representatives, other thanfor the payment of: (1) in a lump sum in cash within thirty (30) days after the Date of Termination (or such earlier date as required by applicable law) thatportion of the Executive’s Annual Base Salary accrued through the Date of Termination to the extent not previously paid, any expense reimbursement accruedand unpaid, any employee benefits pursuant to the terms of the applicable employee benefit plan, and any accrued but unused vacation (the “AccruedObligations”); and (2) any accrued or vested amount arising from the Executive’s participation in, or benefits under, any Incentive Plans (the “AccruedIncentives”), which amounts shall be payable in accordance with the terms and conditions of such Incentive Plans. 4 (b) Death. If the Executive’s employment is terminated by reason of the Executive’s death during the Term, the Company shall haveno further payment obligations to the Executive or Executive’s legal representatives, other than for payment of: (1) a lump sum in cash within thirty (30) daysafter the Date of Termination (or such earlier date as required by applicable law) the Accrued Obligations; and (2) the Accrued Incentives, which shall bepayable in accordance with the terms and conditions of the Incentive Plans. (c) Disability. If the Executive’s employment is terminated by reason of the Executive’s Disability during the Term, the Companyshall have no further payment obligations to the Executive or his legal representatives, other than for payment of: (1) a lump sum in cash within thirty (30)days after the Date of Termination (or such earlier date as required by applicable law) the Accrued Obligations; and (2) the Accrued Incentives, which shall bepayable in accordance with the terms and conditions of the Incentive Plans. (d) Without Cause; For Good Reason. If the Executive’s employment is terminated by the Company without Cause before expirationof the Term, or if the Executive resigns for Good Reason before expiration of the Term, the Company shall have no further payment obligations to the Executiveor his legal representatives, other than for payment of: (1) in a lump sum in cash within thirty (30) days after the Date of Termination (or such earlier date asrequired by applicable law) the Accrued Obligations; (2) the Accrued Incentives, which shall be payable in accordance with the terms and conditions of theIncentive Plans; (3) subject to Section 4(f) below, a lump-sum cash payment, to be made on the first normal payroll date following the Release ConsiderationPeriod (the “Initial Severance Payment Date”) in an amount equal to (x) the average of the annual bonuses paid to the Executive for the three immediatelypreceding completed fiscal years, or (y) if upon the Date of Termination the Executive has not been employed for three complete fiscal years, then the average ofthe annual bonuses paid to the Executive for the years employed with the Company (the “Average Bonus”); and (4) subject to Section 4(f) below, beginningon the Initial Severance Payment Date and thereafter in accordance with the customary payroll practices of the Company, continuation of the Executive’s BaseSalary in effect on the Date of Termination (“Salary Continuation Payments”) for a period of 12 months. Any installments of the Severance Paymentsthat, in accordance with customary payroll practices, would have typically been made during the Release Consideration Period shall accumulate and shall thenbe paid on the Initial Severance Payment Date. The Average Bonus together with the Salary Continuation Payments shall be referred to collectively as the“Severance Payments”. (e) Protected Period: Without Cause; For Good Reason. If the Executive’s employment is terminated by the Company without Causebefore expiration of the Term, or if the Executive resigns for Good Reason before expiration of the Term, in each case, at any time during the Protected Period(as defined below), the Company shall have no further payment obligations to the Executive or his legal representatives, other than: (1) payment in a lump-sum in cash within thirty (30) days after the Date of Termination (or such earlier date as required by applicable law) the Accrued Obligations; (2) payment ofthe Accrued Incentives, which shall be payable in accordance with the terms and conditions of the Incentive Plans; (3) Subject to Section 4(f) below, on theInitial Severance Payment Date, all unvested awards granted to the Executive under the Midstates Petroleum Company, Inc. 2012 Long Term Incentive Plan(the “LTIP”) shall vest, except for (x) any annual cash bonuses granted under the LTIP, and (y) any 5 awards granted under Section 8 of the LTIP or otherwise intended to qualify as “qualified performance-based compensation” under Section 162(m) of theInternal Revenue Code (the “Code”) and any regulations or guidance promulgated thereunder; and (4) Subject to Section 4(f) below, on the Initial SeverancePayment Date, payment of a lump sum cash payment equal to the product of 2 multiplied by the sum of (x) the highest Base Salary paid to the Executiveduring the three years immediately preceding the Change in Control and (y) the highest annual bonus paid to the Executive for the three completed fiscal yearsimmediately preceding the Change in Control (the accelerated vesting enumerated in clause (3) of this Section 4(e), together with the payments enumerated inthis clause (4) of this Section 4(e), collectively the “CIC Severance Payments”). “Protected Period” means the period beginning on the date of a Change inControl (as defined below) and continuing until the one-year anniversary of such Change in Control. “Change in Control” shall have the meaning set forth inthe LTIP. (f) Release and Compliance with this Agreement. The obligation of the Company to pay any portion of the amounts due pursuant toSection 4, with the exception of Accrued Obligations and Accrued Incentives, shall be expressly conditioned on the Executive’s (1) execution (and, ifapplicable, non-revocation) of a full general release, releasing all claims, known or unknown, that the Executive may have against the Company, includingthose arising out of or in any way related to the Executive’s employment or termination of employment with the Company no later than the 60 day followingthe Date of Termination (such period, the “Release Consideration Period”) and (2) continued compliance with the requirements of Sections 7 and 8. (g) Section 409A. Other than the Severance Payments, the amounts payable pursuant to Section 4 of this Plan are intended tocomply with the short-term deferral exception to Section 409A of the Code. To the extent that a Participant is a “specified employee” within the meaning of theTreasury Regulations issued pursuant to Section 409A of the Code as of the Participant’s Date of Termination, no amount that constitutes a deferral ofcompensation which is payable on account of the Participant’s separation from service shall be paid to the Participant before the date (the “Delayed PaymentDate”) which is first day of the seventh month after the Participant’s Date of Termination or, if earlier, the date of the Participant’s death following such Dateof Termination. All such amounts that would, but for this Section 4(g), become payable prior to the Delayed Payment Date will be accumulated and paid onthe Delayed Payment Date. No interest will be paid by the Company with respect to any such delayed payments. For purposes of Section 409A of the Code,each payment or amount due under this Plan shall be considered a separate payment, and a Participant’s entitlement to a series of payments under this Plan isto be treated as an entitlement to a series of separate payments. 5. Excise Taxes. If the Board determines, in its sole discretion, that Section 280G of the Code applies to any compensation payable to theExecutive, then the provisions of this Section 5 shall apply. If any payments or benefits to which the Executive is entitled from the Company, any affiliate,any successor to the Company or an affiliate, or any trusts established by any of the foregoing by reason of, or in connection with, any transaction thatoccurs after the Effective Date (collectively, the “Payments,” which shall include, without limitation, the vesting of any equity awards or other non-cashbenefit or property) are, alone or in the aggregate, more likely than not, if paid or delivered to the Executive, to be subject to the tax imposed by Section 4999of the Code or any successor provisions to that section, then the Payments (beginning with 6th any Payment to be paid in cash hereunder), shall be either (a) reduced (but not below zero) so that the present value of such total Payments received by theExecutive will be one dollar ($1.00) less than three times the Executive’s “base amount” (as defined in Section 280G(b)(3) of the Code) and so that no portionof such Payments received by the Executive shall be subject to the excise tax imposed by Section 4999 of the Code, or (b) paid in full, whichever of (a) or(b) produces the better net after tax position to the Executive (taking into account any applicable excise tax under Section 4999 of the Code and any otherapplicable taxes). The determination as to whether any Payments are more likely than not to be subject to taxes under Section 4999 of the Code and as towhether reduction or payment in full of the amount of the Payments provided hereunder results in the better net after tax position to the Executive shall be madeby the Board and the Executive in good faith. 6. Full Settlement. Neither the Executive nor the Company shall be liable to the other party for any damages for breach of this Agreement inaddition to the amounts payable under Section 4 arising out of the termination of the Executive’s employment prior to the end of the Term; provided, however,that the Company shall be entitled to seek damages from the Executive for any breach of Sections 7 or 8 by the Executive or for the Executive’s criminalmisconduct. 7. Confidential Information. (a) The Executive acknowledges that the Company has trade, business and financial secrets and other confidential and proprietaryinformation (collectively, the “Confidential Information”) which shall be provided to the Executive during the Executive’s employment by the Company. Confidential information includes, but is not limited to, sales materials, technical information, strategic information, business plans, processes andcompilations of information, records, specifications and information concerning customers or venders, customer lists, and information regarding methods ofdoing business. (b) The Executive is aware of those policies implemented by the Company to keep its Confidential Information secret, includingthose policies limiting the disclosure of information on a need-to-know basis, requiring the labeling of documents as “confidential,” and requiring the keepingof information in secure areas. The Executive acknowledges that the Confidential Information has been developed or acquired by the Company through theexpenditure of substantial time, effort and money and provides the Company with an advantage over competitors who do not know or use such ConfidentialInformation. The Executive acknowledges that all such Confidential Information is the sole and exclusive property of the Company. (c) During, and all times following, the Executive’s employment by the Company, the Executive shall hold in confidence and notdirectly or indirectly disclose or use or copy or make lists of any Confidential Information: except (i) to the extent authorized in writing by the Board; (ii) wheresuch information is, at the time of disclosure by the Executive, generally available to the public other than as a result of any direct or indirect act or omissionof the Executive in breach of this Agreement; or (iii) where the Executive is compelled by legal process, other than to an employee of the Company or a personto whom disclosure is reasonably 7 necessary or appropriate in connection with the performance by the Executive of his duties as an employee of the Company. The Executive agrees to usereasonable efforts to give the Company notice of any and all attempts to compel disclosure of any Confidential Information, in such a manner so as to providethe Company with written notice at least five (5) days before disclosure or within one (1) business day after the Executive is informed that such disclosure isbeing or will be compelled, whichever is earlier. Such written notice shall include a description of the information to be disclosed, the court, governmentagency, or other forum through which the disclosure is sought, and the date by which the information is to be disclosed, and shall contain a copy of thesubpoena, order or other process used to compel disclosure. (d) The Executive will take all necessary precautions to prevent disclosure to any unauthorized individual or entity. The Executivefurther agrees not to use, whether directly or indirectly, any Confidential Information for the benefit of any person, business, corporation, partnership, or anyother entity other than the Company. (e) As used in this Section 7, “Company” shall include Midstates Petroleum Company, Inc. and any of its affiliates. 8. Non-Competition; Non-Solicitation. (a) The Executive acknowledges and agrees that the nature of the Confidential Information which the Company commits to providehim during his employment by the Company would make it difficult, if not impossible, for him to perform in a similar capacity for a Competing Business(as defined below) without disclosing or utilizing the Confidential Information. Further, the Executive acknowledges that the Company shall, during the timethat the Executive is employed by Company, (a) disclose or entrust to the Executive, and provide the Executive access to, or place the Executive in a position tocreate or develop, trade secrets or Confidential Information belonging to the Company, (b) place the Executive in a position to develop business goodwillbelonging to the Company and (c) disclose or entrust to the Executive business opportunities to be developed for the Company. Accordingly, in considerationof the foregoing, the Executive agrees that he will not (other than for the benefit of the Company pursuant to this Agreement) directly or indirectly, individuallyor on behalf of any other person, firm, corporation or other entity (whether as an officer, director, employee, shareholder, consultant, contractor, partner, jointventurer, agent, equity owner or in any capacity whatsoever) (1) during the term of Non-Competition (as defined below), carry on or engage in the business ofdeveloping and/or implementing drilling and completion techniques to oil-prone resources in previously discovered yet underdeveloped hydrocarbon trends orin any other business activity that the Company is conducting, or is intending to conduct, on the Date of Termination, in each case in the parishes within theState of Louisiana listed in Exhibit A to this Agreement, the State of Texas, and any other geographical area in which the Company conducts business and, asof the Date of Termination, was planning to conduct business and to which the Executive’s duties as an employee of the Company related (a “CompetingBusiness”), or (2) during the Term of Non-Solicitation (as defined below), (i) hire, attempt to hire, or contact or solicit with respect to hiring any employee,officer, or consultant of the Company, or (ii) solicit, divert or take away any customers, customer leads, or suppliers (as of the Date of Termination) of theCompany. The “Term of Non-Competition” and the “Term of Non-Solicitation” shall be defined as that term beginning on the Effective Date andcontinuing until (x) if the Executive’s employment is 8 terminated by reason of death or Disability, the Date of Termination, or (y) if the Executive’s employment is terminated by the Company for Cause or withoutCause, or by the Executive for Good Reason or without Good Reason, the date that is the one year anniversary of the Date of Termination. (b) Notwithstanding the restrictions contained in Section 8(a), the Executive or any of the Executive’s affiliates may own an aggregateof not more than 2.0% of the outstanding stock of any class of a Competing Business, if such stock is listed on a national securities exchange or regularlytraded in the over-the-counter market by a member of a national securities exchange, without violating the provisions of Section 8(a), provided that neither theExecutive nor any of the Executive’s affiliates has the power, directly or indirectly, to control or direct the management or affairs of any such corporation andis not involved in the management of such corporation. (c) The Executive acknowledges that the geographic boundaries, scope of prohibited activities, and time duration of the precedingparagraphs are reasonable in nature and are no broader than are necessary to maintain the confidentiality and the goodwill of the Company and theconfidentiality of its Confidential Information and to protect the other legitimate business interests of the Company. The Executive further represents andacknowledges that (i) he or she has been advised by the Company to consult his or her own legal counsel in respect of this Agreement, and (ii) that he or shehas had full opportunity, prior to executing this Agreement, to review thoroughly this Agreement with his or her counsel. (d) If any court determines that any portion of this Section 8 is invalid or unenforceable, the remainder of this Section 8 shall notthereby be affected and shall be given full effect without regard to the invalid provisions. If any court construes any of the provisions of this Section 8, or anypart thereof, to be unreasonable because of the duration or scope of such provision, such court shall have the power to reduce the duration or scope of suchprovision and to enforce such provision as so reduced. (e) The Executive’s covenant under this Section 8 of the Agreement shall be construed as an agreement independent of any otherprovision of this Agreement; and the existence of any claim or cause of action of Executive against the Company, whether predicated on this Agreement orotherwise, shall not constitute a defense to the enforcement by the Company of this covenant. (f) As used in this Section 8, “Company” shall include Midstates Petroleum Company, Inc. and any of its affiliates. 9. Mutual Non-Disparagement. The Executive agrees not to intentionally make, or intentionally cause any other Person to make, anypublic statement that is intended to criticize or disparage the Company, any of its affiliates, or any of their respective officers, managers or directors. TheCompany agrees to use commercially reasonable efforts to cause its officers and members of its Board not to intentionally make, or intentionally cause anyother Person t make, any public statement that is intended to criticize or disparage the Executive. This Section 9 shall not be construed to prohibit any personfrom responding publicly to incorrect public statements or from making truthful statements when required by law, subpoena, court order, or the like. 9 10. Miscellaneous. (a) Survival and Construction. Executive’s obligations under this Agreement will be binding upon Executive’s heirs, executors,assigns, and administrators and will inure to the benefit of the Company, its subsidiaries, successors, and assigns. The language of this Agreement shall inall cases be construed as a whole according to its fair meaning, and not strictly for or against any of the parties. The section and paragraph headings used inthis Agreement are intended solely for the convenience of reference and shall not in any manner amplify, limit, modify, or otherwise be used in theinterpretation of any of the provisions hereof. (b) Definitions. As used in this Agreement, “affiliate” means, with respect to a person, any other person controlling, controlled byor under common control with the first person; the term “control,” and correlative terms, means the power, whether by contract, equity ownership orotherwise, to direct the policies or management of a person; and “person” means an individual, partnership, corporation, limited liability company, trust orunincorporated organization, or a government or agency or political subdivision thereof. (c) Notices. All notices and other communications hereunder shall be in writing and shall be given by hand delivery to the otherparty or by registered or certified mail, return receipt requested, postage prepaid, addressed as follows: If to the Executive:Dexter Burleigh12019 Cypress Creek Lakes DriveCypress, TX 77433 If to the Company:Attn: Vice President of Human ResourcesMidstates Petroleum Company, Inc.4400 Post Oak Parkway, Suite 1900Houston, Texas 77027(713) 595-9400 or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notice and communications shall be effective whenactually received by the addressee. (d) Enforcement. If any provision of this Agreement is held to be illegal, invalid or unenforceable under present or future lawseffective during the term of this Agreement, such provision shall be fully severable; this Agreement shall be construed and enforced as if such illegal, invalidor unenforceable provision had never comprised a portion of this Agreement; and the remaining provisions of this Agreement shall remain in full force andeffect and shall not be affected by the illegal, invalid or unenforceable provision or by its severance from this Agreement. Furthermore, in lieu of such illegal,invalid or unenforceable provision there shall be added automatically as part of this Agreement a provision as similar in terms to such illegal, invalid orunenforceable provision as may be possible and be legal, valid and enforceable. 10 (e) Withholding. The Company may withhold from any amounts payable under this Agreement such Federal, state or local taxes asshall be required to be withheld pursuant to any applicable law or regulation as determined by the Company. (f) Section 409A Compliance. This Agreement is intended to comply with (or be exempt from) Code Section 409A and theprovisions of this Agreement shall be construed accordingly. To the extent that any in-kind benefits or reimbursements pursuant to this Agreement are taxableto Executive and constitute deferred compensation subject to Section 409A of the Code, any reimbursement payment due to Executive shall be paid toExecutive on or before the last day of the Executive’s taxable year following the taxable year in which the related expense was incurred. In addition, any suchin-kind benefit or reimbursement is not subject to liquidation or exchange for another benefit and the amount of such benefit or reimbursement that Executivereceives in one taxable year shall not affect the amount of such benefit and reimbursements that Executive receives in any other taxable year. The Executiveagrees to promptly submit and document any reimbursable expenses in accordance with the Company’s reasonable expense reimbursement policies to facilitatethe timely reimbursement of such expenses. (g) No Waiver. No waiver by either party at any time of any breach by the other party of, or compliance with, any condition orprovision of this Agreement to be performed by the other party shall be deemed a waiver of similar or dissimilar provisions or conditions at any time. (h) Equitable and Other Relief. The Executive acknowledges that money damages would be both incalculable and an insufficientremedy for a breach of Sections 7 or 8 by the Executive and that any such breach would cause the Company irreparable harm. Accordingly, the Company, inaddition to any other remedies at law or in equity it may have, shall be entitled, without the requirement of posting of bond or other security, to equitable relief,including injunctive relief and specific performance, in connection with a breach of Sections 7 or 8 by the Executive. In addition to the remedies the Companymay have at law or in equity, violation of Sections 7 or 8 herein will entitle the Company at its sole option not to pay the Average Bonus or the CIC SeverancePayments, to discontinue the Salary Continuation Payments to the Executive, and to seek repayment from the Executive of any Severance Payments or CICSeverance Payments already paid to him by the Company. Such remedies shall not be deemed to be liquidated damages and shall not be deemed the exclusiveremedies for a breach of this Section 7 or 8 but shall be in addition to all remedies available, at law or in equity, including the recovery of damages from theExecutive and his agents. No action taken by the Company under this Section 10(h) shall affect the enforceability of the release and waiver of claims executedby the Executive pursuant to Section 4(f)4(d). (i) Complete Agreement. The provisions of this Agreement constitute the entire and complete understanding and agreement betweenthe parties with respect to the subject matter hereof, and supersedes all prior and contemporaneous oral and written agreements, representations andunderstandings of the parties, which are hereby terminated. Other than expressly set forth herein, the Executive and Company acknowledge and represent thatthere are no other promises, terms, conditions or representations (or written) regarding any matter relevant hereto. This Agreement may be executed in two ormore counterparts. 11 (j) Arbitration. The Company and the Executive agree to the resolution by binding arbitration of all claims, demands, causes ofaction, disputes, controversies or other matters in question (“claims”), whether or not arising out of this Agreement or the Executive’s employment (or itstermination), whether sounding in contract, tort or otherwise and whether provided by statute or common law, that the Company may have against theExecutive or that the Executive may have against the Company or its parents, subsidiaries and affiliates, and each of the foregoing entities’ respective officers,directors, employees or agents in their capacity as such or otherwise; except that this agreement to arbitrate shall not limit the Company’s right to seek equitablerelief, including injunctive relief and specific performance, and damages and any other remedy or relief (including the recovery of attorney fees, costs andexpenses) in a court of competent jurisdiction for an alleged breach of Sections 7 or 8 of this Agreement, and the Executive expressly consents to the non-exclusive jurisdiction of the district courts of the State of Texas for any such claims. Claims covered by this agreement to arbitrate also include claims by theExecutive for breach of this Agreement, wrongful termination, discrimination (based on age, race, sex, disability, national origin or any other factor) andretaliation. In the event of any breach of this Agreement by the Company, it is expressly agreed that notwithstanding any other provision of this Agreement, theonly damages to which the Executive shall be entitled is lost compensation and benefits in accordance with Section 2(b) or 4. The Company and the Executiveagree that any arbitration shall be in accordance with the Federal Arbitration Act (“FAA”) and, to the extent an issue is not addressed by the FAA, with thethen-current National Rules for the Resolution of Employment Disputes of the American Arbitration Association (“AAA”) or such other rules of the AAA asapplicable to the claims being arbitrated. If a party refuses to honor its obligations under this agreement to arbitrate, the other party may compel arbitration ineither federal or state court. The arbitrator shall apply the substantive law of the State of Texas (excluding, to the extent applicable, choice-of-law principlesthat might call for the application of some other state’s law), or federal law, or both as applicable to the claims asserted. The arbitrator shall have exclusiveauthority to resolve any dispute relating to the interpretation, applicability, enforceability or formation of this agreement to arbitrate, including any claim thatall or part of this Agreement is void or voidable and any claim that an issue is not subject to arbitration. The parties agree that venue for arbitration will be inHarris County, Texas, and that any arbitration commenced in any other venue will be transferred to Harris County, Texas, upon the written request of anyparty to this Agreement. In the event that an arbitration is actually conducted pursuant to this Section 10(j), the party in whose favor the arbitrator renders theaward shall be entitled to have and recover from the other party all costs and expenses incurred, including reasonable attorneys’ fees, expert witness fees, andcosts actually incurred. Any and all of the arbitrator’s orders, decisions and awards may be enforceable in, and judgment upon any award rendered by thearbitrator may be confirmed and entered by, any federal or state court having jurisdiction. All proceedings conducted pursuant to this agreement to arbitrate,including any order, decision or award of the arbitrator, shall be kept confidential by all parties. THE EMPLOYEE ACKNOWLEDGES THAT, BYSIGNING THIS AGREEMENT, THE EMPLOYEE IS WAIVING ANY RIGHT THAT THE EMPLOYEE MAY HAVE TO A JURY TRIALOR, EXCEPT AS EXPRESSLY PROVIDED HEREIN, A COURT TRIAL OF ANY EMPLOYMENT-RELATED CLAIM THAT THEEMPLOYEE MAY ALLEGE. (k) Survival. Sections 7, 8 and 9 of this Agreement shall survive the termination of this Agreement. 12 (l) Choice of Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Texas withoutreference to principles of conflict of laws of Texas or any other jurisdiction, and, where applicable, the laws of the United States. (m) Amendment. This Agreement may not be amended or modified at any time except by a written instrument approved by the Boardand executed by the Company and the Executive. (n) Assignment. This Agreement is personal as to the Executive and accordingly, the Executive’s duties may not be assigned by theExecutive. This Agreement may be assigned by the Company without the Executive’s consent to any entity which is a successor in interest to the Company’sbusiness, provided such successor expressly assumes the Company’s obligations hereunder. (o) Executive Acknowledgment. The Executive acknowledges that he has read and understands this Agreement, is fully aware of itslegal effect, has not acted in reliance upon any representatives or promises made by the Company other than those contained in writing herein, and has enteredinto this Agreement freely based on his own judgment. IN WITNESS WHEREOF, the Executive has hereunto set the Executive’s hand and, pursuant to the authorization from the Board, the Companyhas caused this Agreement to be executed in its name on its behalf, all as of the day and year first above written. EXECUTIVE: /s/ Dexter BurleighDexter Burleigh MIDSTATES PETROLEUM COMPANY, INC.,a Delaware corporation By:/s/ John P. FoleyName:John P. FoleyTitle:Corporate Counsel and Secretary 13 Exhibit A · Acadia Parish· Allen Parish· Ascension Parish· Assumption Parish· Beauregard Parish· Calcasieu Parish· Evangeline Parish· East Baton Rouge Parish· East Feliciana Parish· Iberville Parish· Pointe Coupee Parish· Rapides Parish· West Baton Rouge Parish· West Feliciana Parish· Vernon Parish 14Exhibit 12.1 MIDSTATES PETROLEUM COMPANY, INC.RATIO OF EARNINGS TO FIXED CHARGES AND TO COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS(In thousands, except ratios) Year Ended December 31,20132012201120102009 Earnings available before fixed charges:Pre-tax income (loss)(490,514)7,78916,657(15,635)(11,752)Add: Fixed charges115,88124,7555,7232,114981Total additive items(374,633)32,54422,380(13,521)(10,771) Less: Capitalized interest(32,245)(11,175)(2,600)(1,654)(830) Total earnings available for fixed charges$(406,878)$21,369$19,780$(15,175)$(11,601) Interest expensed$77,179$11,711$2,094$—$—Interest capitalized32,24511,1752,6001,654830Amortized premiums, discounts and capitalized expensesrelated to indebtedness5,9601,52985031441Portion of rental expense which represents interest factor (1)497340179146110Total Fixed Charges$115,881$24,755$5,723$2,114$981 Ratio of earnings to fixed charges(b)(c)3.5(d)(e) Total fixed charges$115,881$24,755$5,723$2,114$981Pre-tax preferred dividends (a)22,23010,844——— Total fixed charges plus preferred dividends$138,111$35,599$5,723$2,114$981 Ratio of earnings to combined fixed charges and preferreddividends(b)(c)3.5(d)(e) (a) Prior to October 1, 2012, the Company did not have any preferred stock outstanding. Preferred dividends shown herein relate to the Company’s Series AMandatorily Convertible Preferred Stock (“Series A Preferred Stock”) issued on October 1, 2012, which allows, at the Company’s option, for the 8%annual dividend payment to be made either in cash or through an adjustment to the Series A Preferred Stock liquidation preference. Pre-tax preferred stockdividend amounts for the three months ended March 31, 2013 and the year ended December 31, 2012 were calculated utilizing the Company’s effective taxrate for the applicable periods (39.5% for March 31, 2013 and 40.1% for the year ended December 31, 2012) and represent the notional dividend amountas though paid in cash, rather than through an adjustment to the Series A Preferred Stock liquidation preference.(b) Earnings for the year ended December 31, 2013 were inadequate to cover fixed charges and combined fixed charges and preferred dividends. The coveragedeficiency was $522.8 million and $545.0 million, respectively.(c) Earnings for the year ended December 31, 2012 were inadequate to cover fixed chargesand combined fixed charges and preferred dividends. The coveragedeficiency was $3.4 million and $14.2 million, respectively.(d) Earnings for the year ended December 31, 2010 were inadequate to cover fixed charges and combined fixed charges and preferred dividends. The coveragedeficiency was $17.3 million and $17.3 million, respectively.(e) Earnings for the year ended December 31, 2009 were inadequate to cover fixed charges and combined fixed charges and preferred dividends. The coveragedeficiency was $12.6 million and $12.6 million, respectively. QuickLinks -- Click here to rapidly navigate through this documentEXHIBIT 21.1 List of Subsidiaries of Midstates Petroleum Company, Inc. Entity State of FormationMidstates Petroleum Company LLC DelawareQuickLinksEXHIBIT 21.1List of Subsidiaries of Midstates Petroleum Company, Inc.QuickLinks -- Click here to rapidly navigate through this documentEXHIBIT 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement No. 333-189499 on Form S-3, Registration Statements Nos. 333-190914and 333-190915 on Form S-4, and Registration Statement No. 333-180854 on Form S-8, of our reports dated March 24, 2014, relating to theconsolidated financial statements of Midstates Petroleum Company, Inc. and subsidiary, and the effectiveness of Midstates Petroleum Company, Inc.and subsidiary's internal control over financial reporting (which report expresses an adverse opinion on the effectiveness of the Company's internalcontrol over financial reporting because of a material weakness), appearing in this Annual Report on Form 10-K of Midstates Petroleum Company, Inc.,for the year ended December 31, 2013./s/ DELOITTE & TOUCHE LLPHouston, TexasMarch 24, 2014QuickLinksEXHIBIT 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMQuickLinks -- Click here to rapidly navigate through this documentEXHIBIT 23.2 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS We hereby consent to the references to our firm, in the context in which they appear, and to the references to and the incorporation by reference ofour audit letter as of December 31, 2013, included in the Annual Report on Form 10-K of Midstates Petroleum Company, Inc. for the fiscal year endedDecember 31, 2013, as well as in the notes to the financial statements included therein. We also hereby consent to the incorporation by reference of thereferences to our firm, in the context in which they appear, and to our audit letter as of December 31, 2013, into Midstates Petroleum Company, Inc.'spreviously filed Registration Statement on Form S-8 (No. 333-180854) in accordance with the requirements of the Securities Act of 1933, as amended.Dallas, TexasMarch 24, 2014 NETHERLAND, SEWELL & ASSOCIATES, INC. By: /s/ C.H. (Scott) Rees IIIC.H. (Scott) Rees III, P.E.Chairman and Chief Executive OfficerQuickLinksEXHIBIT 23.2CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTSQuickLinks -- Click here to rapidly navigate through this documentEXHIBIT 23.3 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS Cawley, Gillespie & Associates, Inc., hereby consents to the references to our firm, in the context in which they appear, and to the references toand the incorporation by reference of our summary report dated January 28, 2014 included in the Annual Report on Form 10-K of Midstates PetroleumCompany, Inc. for the fiscal year ended December 31, 2013, as well as in the notes to the financial statements included therein. We hereby furtherconsent to the incorporation by reference of the references to our firm, in the context in which they appear, and to our summary report dated January 28,2014, into Midstates Petroleum Company, Inc.'s previously filed Registration Statement No. 333-189499 on Form S-3, Registration StatementsNos. 333-190914 and 333-190915 on Form S-4, and Registration Statement No. 333-180854 on Form S-8.Sincerely,/s/ Cawley, Gillespie & Associates, Inc.Cawley, Gillespie & Associates, Inc.Texas Registered Engineering Firm F-693March 24, 2014QuickLinksEXHIBIT 23.3CONSENT OF INDEPENDENT PETROLEUM ENGINEERSQuickLinks -- Click here to rapidly navigate through this documentEXHIBIT 31.1 CERTIFICATION I, John A. Crum, certify that:1.I have reviewed this Annual Report on Form 10-K for the period ending December 31, 2013 (the "report") of Midstates PetroleumCompany, 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) and15d-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 oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us byothers within those 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; and d.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 reasonablylikely to materially affect, the registrant's internal control over financial reporting; and 5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, tothe registrant'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; and b.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: March 24, 2014 /s/ JOHN A. CRUMJohn A. CrumChairman, President and Chief Executive OfficerQuickLinksEXHIBIT 31.1CERTIFICATIONQuickLinks -- Click here to rapidly navigate through this documentEXHIBIT 31.2 CERTIFICATION I, Nelson M. Haight, certify that:1.I have reviewed this Annual Report on Form 10-K for the period ending December 31, 2013 (the "report") of Midstates PetroleumCompany, 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) and15d-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 oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us byothers within those 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; and d.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 reasonablylikely to materially affect, the registrant's internal control over financial reporting; and 5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, tothe registrant'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; and b.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: March 24, 2014 /s/ NELSON M. HAIGHTNelson M. HaightSenior Vice President and Chief Financial OfficerQuickLinksEXHIBIT 31.2CERTIFICATIONQuickLinks -- Click here to rapidly navigate through this documentEXHIBIT 32.1 CERTIFICATION Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, John A. Crum, Chairman, Presidentand Chief Executive Officer of Midstates Petroleum Company, Inc. (the "Company"), certifies that, to his knowledge:1.the Annual Report on Form 10-K of the Company for the period ending December 31, 2013, as filed with the Securities and ExchangeCommission on the date hereof (the "Report"), fully complies with the requirements of section 13(a) or 15(d) of the Securities ExchangeAct 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: March 24, 2014 /s/ JOHN A. CRUMJohn A. CrumChairman, President and Chief Executive OfficerQuickLinksEXHIBIT 32.1CERTIFICATIONQuickLinks -- Click here to rapidly navigate through this documentEXHIBIT 32.2 CERTIFICATION Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, Nelson M. Haight, Senior VicePresident and Chief Financial Officer of Midstates Petroleum Company, Inc. (the "Company"), certifies that, to his knowledge:1.the Annual Report on Form 10-K of the Company for the period ending December 31, 2013, as filed with the Securities and ExchangeCommission on the date hereof (the "Report"), fully complies with the requirements of section 13(a) or 15(d) of the Securities ExchangeAct 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: March 24, 2014 /s/ NELSON M. HAIGHTNelson M. HaightSenior Vice President and Chief Financial OfficerQuickLinksEXHIBIT 32.2CERTIFICATIONExhibit 99.1 March 7, 2014 Mr. Curtis NewstromMidstates Petroleum Company, Inc.4400 Post Oak Parkway, Suite 1900Houston, Texas 77027 Dear Mr. Newstrom: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2013, to the MidstatesPetroleum Company, Inc. (Midstates) interest in certain oil and gas properties located in Louisiana and Oklahoma. We completed ourevaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately70 percent of all proved reserves owned by Midstates. The estimates in this report have been prepared in accordance with the definitions andregulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes,conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presentedimmediately following this letter. This report has been prepared for Midstates’ use in filing with the SEC; in our opinion the assumptions,data, methods, and procedures used in the preparation of this report are appropriate for such purpose. We estimate the net reserves and future net revenue to the Midstates interest in these properties, as of December 31, 2013, to be: Net ReservesFuture Net Revenue (M$)OilNGLGasPresent WorthCategory(MBBL)(MBBL)(MMCF)Totalat 10% Proved Developed Producing13,754.96,982.681,455.41,077,325.0669,775.4Proved Developed Non-Producing1,283.6331.13,275.296,583.063,525.7Proved Undeveloped24,045.310,286.8119,855.41,455,175.5723,218.0 Total Proved39,083.717,600.5204,586.02,629,083.51,456,519.0 Totals may not add because of rounding. The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels(MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standardtemperature and pressure bases. The estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties havenot been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts forwhich undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reservessubcategorization is based on development and production status. The estimates of reserves and future revenue included herein have notbeen adjusted for risk. Gross revenue is Midstates’ share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is afterdeductions for Midstates’ share of production taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented inthis report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties. Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in theperiod January through December 2013. For oil and NGL volumes, the average West Texas Intermediate spot price of $96.91 per barrel isadjusted for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $3.670 perMMBTU is adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the livesof the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $98.41 per barrelof oil, $35.68 per barrel of NGL, and $3.236 per MCF of gas. Operating costs used in this report are based on operating expense records of Midstates. These costs include the per-well overhead expensesallowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operatingcosts have been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses ofMidstates are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs arenot escalated for inflation. Capital costs used in this report were provided by Midstates and are based on authorizations for expenditure and actual costs from recentactivity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on ourunderstanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard theseestimated capital costs to be reasonable. Abandonment costs used in this report are Midstates’ estimates of the costs to abandon the wellsand production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation. For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation orcondition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, ourestimates do not include any costs due to such possible liability. We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Midstatesinterest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; ourprojections are based on Midstates receiving its net revenue interest share of estimated future gross production. The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantitiesof oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economicallyproducible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than provedreserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, oractual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certainassumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the propertieswill be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of theinterest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If thereserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because ofgovernmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred inrecovering such reserves may vary from assumptions made while preparing this report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data,production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimatedusing deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating andAuditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standardengineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, thatwe considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. Asubstantial portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient productionhistory upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes andrecovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gasevaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarilyrepresent only informed professional judgment. The data used in our estimates were obtained from Midstates, public data sources, and the nonconfidential files of Netherland, Sewell &Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to theproperties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing theestimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPEStandards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in theseproperties nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC.Texas Registered Engineering Firm F-2699 /s/ C.H. (Scott) Rees IIIBy:C.H. (Scott) Rees III, P.E.Chairman and Chief Executive Officer /s/ Robert C. Barg/s/ Philip R. HodgsonBy:By:Robert C. Barg, P.E. 71656Philip R. Hodgson, P.G. 1314Senior Vice PresidentVice President Date Signed: March 7, 2014Date Signed: March 7, 2014 RCB:DCC Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. Thedigital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to theparameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the originaldocument, the original document shall control and supersede the digital document. DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Alsoincluded is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of PetroleumEngineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Complianceand Disclosure Interpretations. (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses andoptions to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee,brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoirconditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than thereservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When usedto support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir ofinterest: (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);(ii) Same environment of deposition;(iii) Similar geological structure; and(iv) Same drive mechanism. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir ofinterest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with aviscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In itsnatural state it usually contains sulfur, metals, and other non-hydrocarbons. (4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure,but that, when produced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter(from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment isrelatively minor compared to the cost of a new well; and(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction isby means not involving a well. Supplemental definitions from the 2007 Petroleum Resources Management System: Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at thetime of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to berecovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in formarket conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recoveredfrom zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can beinitiated or restored with relatively low expenditure compared to the cost of drilling a new well. Definitons - Page 1 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering andstoring the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment andfacilities and other costs of development activities, are costs incurred to: (i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specificdevelopment drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to theextent necessary in developing the proved reserves.(ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platformsand of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.(iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuringdevices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.(iv)Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economicallyproducible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrateddevelopment of a group of several fields and associated facilities with a common ownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to beproductive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenuethat exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall bedetermined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulativeproduction as of that date. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that areconsidered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphictest wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs)and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of supportequipment and facilities and other costs of exploration activities, are: (i)Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salariesand other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimesreferred to as geological and geophysical or “G&G” costs.(ii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for titledefense, and the maintenance of land and lease records.(iii)Dry hole contributions and bottom hole contributions.(iv)Costs of drilling and equipping exploratory wells.(v)Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to beproductive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, aservice well, or a stratigraphic test well as those items are defined in this section. (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. Definitions - Page 2 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structuralfeature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by interveningimpervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fieldsmay be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended toidentify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A)The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states andoriginal locations;(B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil orgas from such properties;(C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, includingthe acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:(1) Lifting the oil and gas to the surface; and(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and(D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or othernonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with aview to such extraction. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is theoutlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard theterminal point for the production function as: a.The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery,or a marine terminal; andb.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered toa purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, arefinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbonsthat are saleable in the state in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A)Transporting, refining, or marketing oil and gas;(B)Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does nothave the legal right to produce or a revenue interest in such production;(C)Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil andgas can be extracted; or(D)Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceedingproved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability thatthe total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Definitions - Page 3 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations ofavailable data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable todefine clearly the area and vertical limits of commercial production from the reservoir by a defined project.(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in placethan the recovery quantities assumed for probable reserves.(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternativetechnical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons toresults in successful similar projects.(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir withinthe same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or othergeological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions arein communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher orlower than the proved area if these areas are in communication with the proved reservoir.(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and thepotential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoirabove the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of thereservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoirfluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves butwhich, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum ofestimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that theactual quantities recovered will equal or exceed the proved plus probable reserves estimates.(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations ofavailable data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonablecertainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are incommunication with the proved reservoir.(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of thehydrocarbons in place than assumed for proved reserves.(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that couldreasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possibleoutcomes and their associated probabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operatingcosts of support equipment and facilities and other costs of operating and maintaining those wells and related equipment andfacilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: (A) Costs of labor to operate the wells and related equipment and facilities.(B) Repairs and maintenance.(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. Definitions - Page 4 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.(E) Severance taxes. (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation,refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities,their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation,depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also becomepart of the cost of oil and gas produced along with production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience andengineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from knownreservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contractsproviding the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic orprobabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must bereasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to containeconomically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) asseen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contactwith reasonable certainty.(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for anassociated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.(iv) 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: (A) Successful testing by a pilot project in an area of the reservoir with 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 other evidence using reliable technologyestablishes the reasonable certainty of the engineering analysis on which the project or program was based; and(B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Theprice shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined asan unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined bycontractual arrangements, excluding escalations based upon future conditions. (23) Proved properties. Properties with proved reserves. (24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantitieswill be recovered. If probabilistic methods are used, there should be at least a 90% Definitions - Page 5 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is muchmore likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical),engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely toincrease or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has beenfield tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation beingevaluated or in an analogous formation. (26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must bea reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of deliveringoil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until thosereservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separatedfrom a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Suchareas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as ofthe end of the year: a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in theoperation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed inaccordance with paragraphs 932-235-50-3 through 50-11B: a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-endquantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing andproducing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economicconditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration offuture tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of theproperties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s provedoil and gas reserves.d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses fromfuture cash inflows.e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating toproved oil and gas reserves.f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that isconfined by impermeable rock or water barriers and is individual and separate from other reservoirs. Definitions - Page 6 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resourcesmay be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered andundiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wellsinclude gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection forin-situ combustion. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specificgeologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classificationalso includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests areclassified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area. (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recoveredfrom new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain ofproduction when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economicproducibility at greater distances.(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating thatthey are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitivelocations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take intoconsideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years shouldbe the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend pastfive years include, but are not limited to, the following: · The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wellsnecessary to maintain the lease generally would not constitute significant development activities);· The company’s historical record at completing development of comparable long-term projects;· The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;· The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development planseveral times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not beappropriate); and· The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions ondevelopment on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop propertieswith higher priority). (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluidinjection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projectsin the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliabletechnology establishing reasonable certainty. (32) Unproved properties. Properties with no proved reserves. Definitions - Page 7 of 7Exhibit 99.2 January 28, 2014 Mr. Mick MatejkaDirector, Corporate ReservesMidstates Petroleum Company, Inc.4400 Post Oak Parkway, Suite 1900Houston, TX 77027 Re:Evaluation Summary — SEC PricingMidstates Petroleum Company, Inc. InterestsAnadarko BasinProved ReservesAs of January 1, 2014 Dear Mr. Matejka: As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to the above captionedinterests as of January 1, 2014 in certain properties located in Texas and Oklahoma. It is our understanding that the proved reserves estimated in this reportconstitute approximately 30 percent of all proved reserved owned by Midstates Petroleum Company, Inc. This report, completed on January 28, 2014, hasbeen prepared for use in filings with the SEC by Midstates Petroleum Company, Inc. Composite reserve estimates and economic forecasts are presented in the attached tables and are summarized below: ProvedDevelopedProvedProvedProducingUndevelopedNet ReservesOil/Condensate- Mbbl15,815.54,814.511,001.0Gas- MMcf75,612.426,679.648,932.8NGL- Mbbl8,555.23,007.45,547.8RevenueOil/Condensate- M$1,489,028.0453,610.51,035,417.4Gas- M$258,756.091,382.2167,373.9NGL- M$322,873.6113,498.5209,375.2Severance and Ad Valorem Taxes- M$139,189.646,099.293,090.4Operating Expenses- M$469,843.8209,252.1260,591.8Investments- M$493,446.38,172.8485,273.5Operating Income (BFIT)- M$968,177.9394,967.0573,210.8Discounted @ 10%- M$611,314.7292,297.9319,016.8 The discounted value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc. As requested, hydrocarbon pricing of $3.670 per MMBtu of gas (Henry Hub) and $96.78 per barrel of oil/condensate (WTI Cushing) was appliedwithout escalation. In accordance with the Securities and Exchange Commission guidelines, these prices were determined as an unweighted arithmetic averageof the first-day-of-the-month price for the previous 12 months. NGL prices were forecast as 39% of the above oil prices. Basis differentials were applied tothe oil and gas prices, and deductions were applied to the net gas volumes for fuel and shrinkage. The adjusted volume-weighted average product prices overthe life of the properties are $94.15 per barrel of oil, $3.42 per Mcf of gas and $37.74 per barrel of NGL. Operating expenses were based on operating expense records of Midstates Petroleum Company, Inc. Drilling and completion costs were based onestimates provided by Midstates Petroleum Company, Inc. and reviewed by Cawley, Gillespie & Associates. Severance tax and ad valorem rates werespecified by state/county based on actual rates. Plugging and abandonment costs of $43,000 (net of salvage value) were applied to all wells. Neither expensesnor investments were escalated. The proved reserve classifications conform to criteria of the Securities and Exchange Commission. The reserves were estimated using a combinationof the production performance, volumetric and analogy methods, in each case as we considered to be appropriate and necessary to establish the conclusions setforth herein. The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on theeffective date except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. Allreserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatoryconditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than theestimated amounts. The reserve estimates were based on interpretations of factual data furnished by Midstates Petroleum Company, Inc. Ownership interests weresupplied by Midstates Petroleum Company, Inc. and were accepted as furnished. To some extent, information from public records has been used to checkand/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has cometo our attention, however, that would cause us to believe that we are not justified in relying on such data. An on-site inspection of these properties has not beenmade nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Our work-papers and related data are available for inspection and review by authorized parties. Respectfully submitted, CAWLEY, GILLESPIE & ASSOCIATES, INC.Texas Registered Engineering Firm F-693 2Executive Officers Dr. Peter J. Hill Interim President and Chief Executive Officer Nelson M. Haight Senior Vice President and Chief Financial Officer Curtis A. Newstrom Senior Vice President—Business Development Dexter A. Burleigh Senior Vice President—Strategic Planning and Treasury Gregory F. Hebertson Senior Vice President—Exploration Board of Directors Thomas C. Knudson Interim Chairman and Director Dr. Peter J. Hill Director George A. DeMontrond Director Loren M. Leiker Director Stephen J. McDaniel Director John Mogford Director Mary P. Ricciardello Director Robert M. Tichio Director Corporate Information Corporate Office 4400 Post Oak Parkway Suite 1900 Houston, Texas 77027 713-595-9400 www.midstatespetroleum.com Tulsa Office 321 South Boston Avenue Suite 1000 Tulsa, Oklahoma 74103 918-947-8550 Annual Meeting The Annual Meeting of Stockholders will be held in Houston, Texas on Friday, May 23, 2014 Registrar and Transfer Agent American Stock Transfer and Trust Company Shareholder Services 6201 15th Street Brooklyn, New York 11219 800-937-5449 www.amstock.com m o c . s r o n n o c - n a r r u c . w w w / . c n I , s r o n n o C & n a r r u C y b n g i s e D t r o p e R l a u n n A Midstates Petroleum Company, Inc. 4400 Post Oak Parkway, Suite 1900 Houston, Texas 77027 713-595-9400 www.midstatespetroleum.com

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