Amplify Energy Corp. - Annual Report: 2013 (Form 10-K)

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MIDSTATES PETROLEUM COMPANY, INC. TABLE OF CONTENTS
MIDSTATES PETROLEUM COMPANY, INC. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

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

Form 10-K

Commission File Number: 001-35512

MIDSTATES PETROLEUM COMPANY, INC.
(Exact name of registrant as specified in its charter)

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

         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 ý

         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 ý

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    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 the Form 10-K ý

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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 ý

         The aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant was approximately $180 million based upon the 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 per share.

         The number of shares outstanding of our stock at March 18, 2014 is shown below:

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MIDSTATES PETROLEUM COMPANY, INC.
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CAUTIONARY 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 are beyond 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:

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business strategy;



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estimated future net reserves and present value thereof;



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technology;



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cash flows and liquidity;



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financial strategy, budget, projections and operating results;



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oil and natural gas realized prices;



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timing and amount of future production of oil and natural gas;



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availability of drilling and production equipment;



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availability of oilfield labor;



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availability of third party natural gas gathering and processing capacity;



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the amount, nature and timing of capital expenditures, including future development costs;



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availability and terms of capital;



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drilling of wells, including our identified drilling locations;



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successful results from our identified drilling locations;



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marketing of oil and natural gas;



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the integration and benefits of asset and property acquisitions or the effects of asset and property acquisitions or dispositions on our cash position and levels of indebtedness;



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infrastructure for salt water disposal and electricity;



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sources of electricity utilized in operations and the related infrastructures;



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costs of developing our properties and conducting other operations;



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general economic conditions;



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effectiveness of our risk management activities;



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environmental liabilities;



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counterparty credit risk;



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the outcome of pending and future litigation;



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governmental regulation and taxation of the oil and natural gas industry;



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developments in oil-producing and natural gas-producing countries;

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uncertainty regarding our future operating results; and



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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-looking statements. 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 no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" and elsewhere in this annual report.

        These factors include:

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variations in the market demand for, and prices of, oil, natural gas liquids and natural gas;



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uncertainties about our estimated quantities of oil and natural gas reserves;



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the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our revolving credit facility;



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access to capital and general economic and business conditions;



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uncertainties about our ability to replace reserves and economically develop our current reserves;



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risks in connection with acquisitions, including the Eagle Property and Anadarko Basin Acquisitions;



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risks related to the concentration of our operations onshore in Oklahoma, Texas and Louisiana;



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drilling results;



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the potential adoption of new governmental regulations; and



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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 our management 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. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

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GLOSSARY 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, or in 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 production do 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 in another 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 in 100 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 reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience 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 reasonable certainty. 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 reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the 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 technology establishes the reasonable certainty of the engineering analysis on which the project or program 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 average price during the 12-month period prior to the ending date of the

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period 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 an attempt 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 given date 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 is confined 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 working interest owners bear the exploration, development, and operating costs on a cash, penalty, or carried basis.

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PART 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 are influenced 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 historical periods since April 25, 2012, refer to Midstates Petroleum Company, Inc. and its subsidiary, and for historical periods prior to April 25, 2012, refer to Midstates 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 holding company for Midstates Petroleum Company LLC ("Midstates Sub"), which was previously a wholly-owned subsidiary of Midstates Petroleum Holdings LLC. Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Midstates Petroleum Company, Inc.'s initial public offering on April 25, 2012, all of the interests in Midstates Petroleum Holdings LLC were exchanged for newly issued common shares of Midstates Petroleum Company, Inc., and as a result, Midstates Sub became a wholly-owned subsidiary of Midstates Petroleum Company, Inc. and Midstates Petroleum Holdings LLC ceased to exist as a separate entity. Our common stock, par value $0.01 per share, has been listed 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 and undeveloped acreage located primarily in the Mississippian Lime liquids play in Oklahoma for $325 million in cash, before customary post-closing adjustments, and 325,000 shares of the Company's Series A Mandatorily Convertible Preferred Stock (the "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 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 and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (the "Anadarko Basin Acquisition"), before customary 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 Senior Notes, 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 and properties in Louisiana, Oklahoma and Texas. At December 31, 2013, the Company operated oil and natural gas properties and evaluated performance as 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 undeveloped acreage in the Pine Prairie field area of Evangeline

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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 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 the Pine Prairie field. 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 the PSA discussed above):

        During 2013, we incurred $1.2 billion in exploration, development and property acquisition expenditures, including $624.7 million for the Anadarko Basin Acquisition and $64.9 million for facilities and lease and seismic acquisition. Of the 124 wells spud in 2013, 121 gross (98 net) wells

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resulted 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 through the following strategies:

        Development of our multi-year drilling inventory.    We intend to drill and develop our current acreage position to maximize the value of our primarily oil and liquids rich resource potential.

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Mississippian.  Our Mississippian assets acquired on October 1, 2012 are located in Oklahoma and target the Mississippian Lime and Hunton formations. The Mississippian Lime is an expansive carbonate hydrocarbon system located in the Anadarko Basin, primarily in northern Oklahoma. We currently intend to continue development of these liquids rich properties using horizontal wells and multi-stage frac 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 until natural 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 Mississippian Lime 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.



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Anadarko Basin.  Our Anadarko Basin assets acquired on May 31, 2013 are located in Western Oklahoma and Texas and target multiple objectives in the Pennsylvanian section. Specifically we are currently targeting the Cleveland, Marmaton, Cottage Grove and Tonkawa formations 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 Oklahoma and approximately 118,800 gross (95,500 net) acres in the Texas. As of December 31, 2013, we had five drilling rigs in operation in this area, 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.



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Gulf Coast.  Our Gulf Coast assets are located in Louisiana and are characterized by thick geologic sections of tight sands within the Tertiary Wilcox featuring multiple productive zones located within large geologic structural traps that are identifiable with 2D and 3D seismic data. Our primary operating areas have well-established production histories. At December 31, 2013 we had approximately 83,400 gross (81,200 net) acres under lease and/or lease option, comprised of 58,500 gross (56,500 net) acres under lease and 24,900 gross (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 to those 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 area and expect a reduction in activity versus prior year due to our current focus on exploitation of our Mississippian assets and our recently

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acquired Anadarko Basin Assets. As discussed above, 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 of Evangeline Parish, Louisiana to a private buyer. Acreage subject to the 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 financial stability. We believe that this approach includes targeting a conservative leverage profile and maintaining the liquidity to develop our asset base across industry cycles, as well as evaluating capital allocation decisions in the context of these goals. We have historically funded our activity through a combination of equity and debt securities, bank debt, and cash generated by operations. For example, we funded the Eagle Property Acquisition with a combination of cash proceeds from our $600 million 2020 Senior Notes offering and through the issuance of our Series A Preferred Stock. We funded the Anadarko Basin Acquisition with cash proceeds from our $700 million 2021 Senior Notes offering. In September 2013, our reserve-based borrowing base under our revolving credit facility was increased from $425 million to $500 million. To reduce variability in cash flow from our properties and to enhance our reserve based borrowing facility, we periodically enter into commodity derivative contracts and target hedging the maximum volumes permitted under our revolving credit facility, which currently equates to approximately 80% of our total current oil volumes from proved developed producing reserves. We believe the resulting increase in the predictability of our cash flow allows us to better schedule our development activities and maximize the productivity of those efforts. We may also consider the sale of selected assets or oil and gas interests to the extent 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 as operator on the majority of our properties, provide flexibility with respect to drilling and completion techniques and the timing and amount of capital expenditures 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 reservoir evaluation 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 significant exploration and development potential. These areas become targets for our leasing activity. Once we have identified a potential target, we attempt to maximize 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 to better understand the ultimate potential of a particular area. We believe future development across our acreage position can be further optimized with specialized 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 the Mississippian Lime, Anadarko Basin and the Upper Gulf Coast Tertiary trend, we continue to strategically increase our leasehold position in what we believe are the most prospective areas of our acreage. We believe our current Oklahoma and Texas acreage is highly prospective in the Pennsylvanian and Mississippian Lime sections and may be prospective in both shallower and deeper geologic sections. We plan to continue targeting additional onshore basins in North America that would allow us to extend our competencies to large undeveloped acreage positions in hydrocarbon trends similar to our existing core areas.

        Apply rigorous investment analysis to capital allocation decisions.    We employ rigorous investment analysis to determine the allocation of capital across our many drilling opportunities and in evaluating potential acquisitions. We are focused on maximizing the internal rate of return on our investment

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capital and screen drilling opportunities and acquisition opportunities by measuring risk and financial return, among other factors. We continually evaluate our inventory of potential investments by these measures, incorporating past drilling results, historical knowledge and new information we have 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 locations are 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 our oil production to the Louisiana Light Sweet ("LLS") market, which has historically commanded a premium to West Texas Intermediate ("NYMEX WTI") 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 has averaged approximately $14.88 per Bbl for the three years ended December 31, 2013. For the year ended December 31, 2013, the average realized price before the effect of commodity derivative contracts for our oil production was $99.18 per Bbl, compared to an average NYMEX WTI price of $98.05 per 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 our predecessor in the field have demonstrated an early mover advantage in acquiring and developing acreage in the trend, spudding 151 horizontal wells between 2010 and December 31, 2013. We believe our Mississippian team's early experience operating in this trend gives us a competitive advantage with respect to completion techniques and infrastructure development. In the Anadarko Basin area, we also feel that we have an advantage due to the history of drilling horizontally in several of the Pennsylvanian sands since 2005. We successfully hired many of the operation and technical personnel from 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 Tertiary trend since 1993. We believe our extensive operating experience in the trend provides us with an expansive technical understanding of the geology underlying our acreage and of the application of completion technologies and infrastructure design and optimization to our properties. We believe our relatively long history in the Gulf Coast area and experience interpreting well control data, core data and 2D and 3D seismic data provides us with an information advantage over our competitors in this trend and has allowed us to identify and acquire quality acreage at a relatively low cost. We believe we have developed amicable and mutually beneficial relationships with acreage owners in all of our core operating areas, which we believe also provides us with a competitive advantage with respect to our leasing and development activity. We also benefit from long-term relationships with local service 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 oil and gas industry and significant public company executive experience at major and large independent oil and gas companies and oilfield services companies, including Apache Corporation, Burlington Resources, ConocoPhillips and Anadarko Petroleum Corporation. Our management team has an average of 30 years of industry experience, including prior experience in various trends across the US and internationally. We believe our management team is one of our principal competitive strengths relative to our industry peers due to our team's proven track record of efficiently operating exploration and development programs. Additionally, our management team has a significant ownership interest in us, which we believe

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provides 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 Operations

Mississippian Lime

        Our Mississippian assets were acquired on October 1, 2012 and at December 31, 2013, consisted of approximately 84,300 net prospective acres in the 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 average working 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 was as 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 wells per 640 acre section. We are also testing different completion techniques, including selective use of open hole completions, to determine the most cost effective 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 actively develop 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 plan to run one (or more) rigs in these areas to not only hold acreage but also de-risk the acreage.

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Anadarko Basin

        Our Anadarko Basin assets were acquired on May 31, 2013, and at December 31, 2013, consisted of approximately 129,800 net acres in the Anadarko Basin, consisting of 95,500 net acres in Texas and 34,300 net acres in western Oklahoma. We took over operations of the properties on December 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 average working 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 the area 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 while testing 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 Coast Tertiary trend and is characterized by well-defined geology, including tight sands featuring multiple productive zones typically located within large geologic traps. As of December 31, 2013, we had accumulated approximately 56,500 net acres in the trend and options to acquire an aggregate of approximately 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 production from multi-stage hydraulically fractured completions across stacked oil-producing intervals. As of December 31, 2013, we had drilled 144 wells in the trend, approximately 92% of which produced commercially, since the third quarter of 2008. Since that time, we have increased our average daily production 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 average working interest and average net revenue interest of 97% and 73%; respectively, on our acreage in this area.

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        For the quarter ended December 31, 2013 and 2012, and years ended December 31, 2013 and 2012, our average daily production from the area was 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 rigs operating in this area as we have devoted our capital to developing our Mississippian and Anadarko Basin assets; however, we plan to continue to evaluate 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, South Bearhead Creek and North Coward's Gully. In Pine Prairie we spent $31.2 million of capital in 2013, continuing our vertical development of the deeper objectives 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 Creek spudding two horizontals and one vertical. Lastly, in 2013, we spent $55.6 million in capital and spud four horizontals, including one sidetrack, in the North 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 of Evangeline Parish, Louisiana to a private buyer for a purchase price of $170 million, subject to standard post-closing adjustments. The PSA 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 the Pine Prairie field. Production from the assets included in this 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 the fourth quarters ended December 31, 2013 and 2012, respectively. Upon closing of the sale, our remaining Gulf Coast areas of operation will be concentrated in the South Bearhead and North Coward's Gully fields.

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Estimated 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 end 2012 to year end 2013. Our reserve growth in these periods is due directly to the extensions and discoveries associated with our drilling activities in each year and, during 2012, the Eagle Property Acquisition and during 2013, the Anadarko Basin Acquisition. As a result, we have increased our average 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 year ended 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 this time, we spent $249.2 million of our capital expenditures on drilling proved undeveloped locations and converted 11.3 MMBoe from proved undeveloped reserves to proved developed reserves. In addition, we added 43.6 MMBoe of proved

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undeveloped reserves through extensions and discoveries and had negative revisions of 20.2 MMBoe related to proved undeveloped reserves, of which 14.4 MMBoe related to reductions at our Gulf Coast Pine Prairie and West Gordon fields. These net negative revisions in the Gulf Coast were primarily due 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 engineers

Mississippian 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 reports prepared by Netherland, Sewell & Associates, Inc. ("NSAI"), in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines in effect during such period established by the SEC. Our estimated reserves and related future net revenues for all areas at December 31, 2012 and 2011 were based on reports prepared by NSAI, in accordance with generally accepted petroleum engineering and evaluation principles 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 of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible 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 of reserves. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Hodgson has been practicing 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 in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. All technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; all are proficient in judiciously applying industry standard practices to 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 and guidelines 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 industry and financial organizations and government agencies. CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the reserves report incorporated herein was

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Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 26 years of practical experience in petroleum engineering, with over 24 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

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, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

        In order to establish reasonable certainty with respect to our estimated proved reserves, NSAI and CGA employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and 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 to ensure the integrity, accuracy and timeliness of data furnished to NSAI and CGA in their reserves estimation process. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from the Company's accounting records, which are subject to external quarterly reviews, annual audits and their own set of internal controls over financial reporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. The Company's current ownership in mineral interests and well production data are incorporated into the reserve database as well and verified to ensure their accuracy and completeness. At December 31, 2013, Clifford G. Zwahlen, PE, our former Vice President—Corporate Reserves, was the technical person primarily responsible for overseeing the preparation of our reserve estimates and reported directly to the CEO. Prior to joining Midstates in March 2013, Mr. Zwahlen was the Manager of Reservoir Engineering—Southern Region for Devon Energy, an oil and gas exploration and production company, from November 2011 to February 2013. Prior to that, from September 2009 to October 2011, he was the Reservoir Engineering

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Manager and Asset Lead for Devon's Carthage District in East Texas. From February 2008 to August 2009, Mr. Zwahlen was the Director of the Project Management Office for Devon's Shared Services Group and from March 2005 to February 2008 he held the position of Manager of Corporate Planning for Devon's Exploration and Production Business Unit. He also held management and engineering positions with EOG Resources and PetroCorp, Inc. Mr. Zwahlen currently serves on the Advisor Board for the MPGE School of the University of Oklahoma and the Petroleum Engineering Industry Board at Texas A&M University. He holds a degree in Petroleum Engineering from Texas A&M University and is a registered Professional Engineer in the state of Texas (License No. 76924). Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the reserve report 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 of December 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 third party reserve engineers. We also did not perform adequate management review of the independent third party reserves reports to determine if reserves estimates 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 and demand. Demand for oil and natural gas in the United States has increased dramatically during the past decade. However, the current economic slowdown during the second half of 2008 and through 2009 reduced this demand. Demand for oil increased during 2010, 2011 and 2012, but demand for natural gas has remained sluggish. Additionally, the price of natural gas has remained relatively depressed due to increasing supplies from shale plays, 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 price volatility. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets. The following table sets forth information regarding oil, natural gas liquids and natural gas production, revenues and realized prices and production costs for the years ended December 31, 2013, 2012 and

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2011. For additional information on price calculations, see information set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operation."

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        The following table sets forth information regarding oil, NGLs and natural gas production for each of the fields that represented more than 15% of our 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 in gross wells.

Acreage

        The following table sets forth certain information regarding the developed and undeveloped acreage in which we have a controlling interest as of December 31, 2013 for each of our operating areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

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Undeveloped 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 by operating area unless production is established within the spacing units covering the acreage or we make additional lease rental payments prior to the expiration dates:

        Excluding the Anadarko Basin Acquisition, approximately 12% of our net acreage, including acreage under option, was acquired in 2013, with the majority of such leases under three year primary term leases. In addition, our typical lease terms along with unit regulatory rules generally provide us flexibility 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 all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.