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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2012

OR

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

For the transition period from                    to                     

Commission File Number: 001-35512

MIDSTATES PETROLEUM COMPANY, INC.

(Exact name of registrant as specified in its charter)

(713) 595-9400

(Registrant’s telephone number, including area code)

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 o No x

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 x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (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 x

The number of shares outstanding of our common stock at May 22, 2012 is shown below:

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MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2012

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GLOSSARY OF OIL AND NATURAL GAS TERMS

Basin: A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl: One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or natural gas liquids.

Bcf: One billion cubic feet of natural gas.

Boe: Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d: Barrels of oil equivalent per day.

British thermal unit (BTU): The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion:  The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage: The number of acres that are allocated or assignable to productive wells or wells capable of production.

Developed reserves:  Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor when 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 is by means not involving a well.

Development well: A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

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.

Economically producible: A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

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.

Field: An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Formation: A layer of rock which has distinct characteristics that differ from nearby rock.

Horizontal drilling: A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Infill drilling: A drilling technique used in certain formations where a well is drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

MBbl: One thousand barrels of oil, condensate or natural gas liquids.

MBoe: One thousand barrels of oil equivalent.

Mcf:  One thousand cubic feet of natural gas.

MMBbl: One million barrels of oil, condensate or natural gas liquids.

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MMBoe: One million barrels of oil equivalent.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

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.

Productive well: A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Proved developed reserves: Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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, LKH, 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, HKO, 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 shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves (PUD): Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Reasonable certainty: A high degree of confidence.

Recompletion: The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in 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.

Rotary sidewall coring: A technique for collecting core samples where a miniaturized automated rotary drilling tool is applied to the side of the borehole to cut a sample from the subject material.

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Sidetracking: The workover term for drilling a directional hole to bypass an obstruction in the well that cannot be removed or damage to the well, such as collapsed casing that cannot be repaired. Sidetracking is also done to deepen a well or to relocate the bottom of the well in a more productive zone, which is horizontally removed from the original well.

Slim - hole drilling: A drilling technique in which the size of the hole is smaller than the conventional hole diameter for a given depth.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

Spud: The commencement of drilling operations of a new well.

Unit: The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

Wellbore: The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

Working interest: The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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PART I - FINANCIAL INFORMATION

MIDSTATES PETROLEUM HOLDINGS LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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MIDSTATES PETROLEUM HOLDINGS LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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MIDSTATES PETROLEUM HOLDINGS LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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MIDSTATES PETROLEUM HOLDINGS LLC

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Business

Midstates Petroleum Company, Inc. (“MPCI”), through its wholly owned subsidiary Midstates Petroleum Company LLC, engages in the business of drilling for, and production of, oil, natural gas and natural gas liquids. MPCI currently has oil and gas operations solely in the state of Louisiana.

MPCI 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, 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 MPCI’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 MPCI, and as a result,  Midstates Petroleum Company LLC became a wholly-owned subsidiary of MPCI and Midstates Petroleum Holdings LLC ceased to exist as a separate entity.

As of the date of the unaudited financial statements included in this Quarterly Report on Form 10-Q for the three month period ended March 31, 2012, the corporate reorganization referred to above had not occurred and operations were conducted through Midstates Petroleum Holdings LLC and its subsidiary Midstates Petroleum Company LLC.  Therefore, the unaudited financial statements included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2012 are those of Midstates Petroleum Holdings LLC (the “Company”) and Midstates Petroleum Company LLC (the “Subsidiary”). In this Quarterly Report on Form 10-Q, the terms “we,” “us,” and “our” refer to MPCI, and the term “Company” refers to Midstates Petroleum Holdings LLC.

At March 31, 2012, the Company was 76.73% owned by FR Midstates Holdings LLC (“FR Midstates”) and 22.64% owned by Midstates Petroleum Holdings, Inc. (“Petroleum Inc.”), through which the Company’s founders, management and certain employees held their equity interests, and 0.63% owned by certain members of management and employees.

At March 31, 2012, the Company operated its oil and natural gas properties as one business segment: the exploration, development and production of oil, natural gas and natural gas liquids. The Company’s management evaluated performance based on one business segment as there were not different economic environments within the operation of the Company’s oil and natural gas properties.

All pro forma share and per share information presented in the accompanying unaudited financial statements have been adjusted to reflect the effects of the initial public offering.

2. Summary of Significant Accounting Policies

Basis of Presentation

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements, and should be read with the audited consolidated financial statements and notes thereto included in MPCI’s Registration Statement on Form S-1, as amended (Registration No. 333-177966).

All intercompany transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year’s consolidated financial statements and related footnotes to conform them to the current year presentation. In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

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Pro Forma Financial Information

Income Taxes.

For the periods presented, the Company was not a taxpaying entity for federal income tax purposes and, accordingly, it did not recognize any expense for such taxes. Any federal or state income tax liability resulting from the Company’s activities prior to the corporate reorganization discussed above was the responsibility of the Company’s members. In the event taxing authorities examine the Company’s tax returns, the tax liability of the members could be changed if an adjustment of the Company’s income or loss is ultimately sustained.

The unaudited pro forma income tax expense (benefit) presented in the condensed consolidated statements of operations reflects the effect on operations as if the Company had been a tax paying entity in the form resulting from the corporate reorganization related to the initial public offering. The pro forma effective tax rate of 40.2% for the periods presented differs from the expected federal statutory rate of 35% due to state income taxes of up to 8.0% (or 5.2%, net of the federal benefit). For both periods presented, there were no material permanent differences. No valuation allowance was deemed necessary due to the presence of future net taxable amounts (primarily attributable to oil and gas producing properties) in excess of deferred tax assets; management placed no reliance on other sources of future taxable income.

The Company, on a pro forma basis, would have recorded a tax benefit during the three months ended March 31, 2012 and 2011 of $7.0 million and $6.5 million, respectively. In addition, the pro forma recalculation of the ceiling test for the three months ended March 31, 2012 and 2011 on an after tax basis did not indicate any impairment of the Company’s oil and gas properties.

Loss per Share.

All pro forma share and per share information presented in the accompanying unaudited condensed consolidated financial statements have been adjusted to reflect the shares issued as a result of the initial public offering discussed above. Pro forma net loss per basic and diluted share is determined by dividing the pro forma net loss by the number of common shares outstanding immediately after the initial public offering, which closed on April 25, 2012.

Recent Accounting Pronouncements

The Company reviewed recently issued accounting pronouncements that became effective during the three months ended March 31, 2012, and determined that none would have a material impact on the Company’s condensed consolidated financial statements.

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 into two 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 cost and 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 for the asset or liability. Fair value assets and liabilities that are generally included in this category are commodity derivative contracts with fair values based on inputs from actively quoted markets. The Company uses a market approach to estimate the fair values of its commodity derivative contracts, utilizing commodity futures price strips for the underlying commodities provided by a reputable third-party.

·                  Level 3 — Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.

Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

Derivative Instruments — Commodity derivative contracts reflected in the condensed consolidated balance sheets are recorded at estimated fair value. At March 31, 2012 and December 31, 2011, all of the Company’s commodity derivative contracts were with two bank counterparties and are classified as Level 2.

Derivative instruments listed above are presented gross and include collars, swaps, and put options that are carried at fair value. The Company records the net change in the fair value of these positions in “Losses on commodity derivative contracts — net” in the Company’s unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company classifying its derivatives as Level 2 instruments. This observable data includes the forward curve for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves.

For additional information on the Company’s derivative instruments and balance sheet presentation, see Note 4.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s condensed consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Asset Retirement Obligations (ARO’s) — The Company initially estimates the fair value of ARO’s based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, the amount and timing of settlements, the credit-adjusted risk-free rate and inflation rates. See Note 5 for a summary of changes in ARO’s.

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4. Risk Management and Derivative Instruments

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. The Company believes it is prudent to manage the variability in cash flows by entering into derivative financial instruments to economically hedge a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and options, to manage fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are generally placed with major financial institutions that the Company believes are minimal credit risks. The oil and gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production.

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Had the Company’s counterparties failed to perform under existing commodity derivative contracts, no loss would have been incurred at March 31, 2012 due to these netting arrangements.

Commodity Derivative Contracts

As of March 31, 2012, the Company had the following open commodity positions:

(1)          2012 deferred premium puts represent the net effective floor price of a put with a strike price of $85.00/Bbl and a deferred premium of $5.99/Bbl. The premiums for these instruments are paid each month, concurrently with the settlement of the monthly put contracts.

(2)          The Company enters into swap arrangements intended to capture the positive differential between the Louisiana Light Sweet (“LLS”) pricing and West Texas Intermediate (“NYMEX WTI”) pricing.

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Balance Sheet Presentation

The following table summarizes the gross fair value of derivative instruments by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s condensed consolidated balance sheets at March 31, 2012 and December 31, 2011, respectively (in thousands):

(1)          The fair value of derivative instruments reported in the Company’s condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net derivative fair values as reported in the Company’s condensed consolidated balance sheets as of March 31, 2012 and December 31, 2011, respectively (in thousands):

Losses on Commodity Derivative Contracts

The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, all gains and losses, including unrealized gains and losses from changes in the derivative instruments’ fair values, have been recorded in “Losses on commodity derivative contracts — net”, within revenues in the condensed consolidated statements of operations.

For the three months ended March 31, 2012 and March 31, 2011, the Company realized net losses of $6.5 million and $2.0 million, respectively.

For the three months ended March 31, 2012 and March 31, 2011, the Company recorded net unrealized losses of $18.2 million and $26.6 million, respectively, related to the change in fair value of the derivative financial instruments in “Losses on commodity derivative contracts — net.”

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5. Asset Retirement Obligations

For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the asset retirement obligation at inception is capitalized as part of the carrying amount of the related long-lived assets. Asset retirement obligations approximated $8.2 million and $7.6 million as of March 31, 2012 and December 31, 2011, respectively.

The liability has been accreted to its present value as of March 31, 2012 and December 31, 2011. The Company evaluated its wells and determined a range of abandonment dates through 2058.

The following table reflects the changes in the Company’s asset retirement obligations for the three months ended March 31, 2012 (in thousands):

6. Long-Term Debt

The Company’s long-term debt as of March 31, 2012 and December 31, 2011 is as follows (in thousands):

As of March 31, 2012, the Company’s credit facility consisted of a $300 million senior revolving credit facility (the “Facility”) with a borrowing base of $210 million, which was most recently redetermined in March 2012. The Facility has a maturity date of December 10, 2014. Borrowings under the Facility are secured by substantially all of the Company’s oil and natural gas properties. Borrowings under the Facility currently bear interest at LIBOR plus an applicable margin between 2.00% and 2.75% per annum. At March 31, 2012 and December 31, 2011, the weighted-average interest rate was 3.1% and 3.2%, respectively.

In addition to interest expense, the credit agreement requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.5% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

The borrowing base is subject to semiannual redeterminations in March and September and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by the Company or the administrative agent, acting on behalf of lenders holding at least two —thirds of the outstanding loans and other obligations.

Under the terms of the Facility, the Company is required to repay the amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base. Under the terms of the Facility, the Company is permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction. At March 31, 2012, as a result of the March 2012 redetermination that reduced the Company’s borrowing base from $235 million to $210 million, $25.0 million is classified as the current portion of long-term borrowings and represents the amount of outstanding borrowings and obligations in excess of the revised borrowing base. On April 20, 2012 the Company made the first of the monthly repayments in an amount of approximately $4.2 million. On April 25, 2012, we repaid approximately $99.0 million of the outstanding Facility balance with a portion of the proceeds from our initial public offering, resulting in an outstanding balance under the Facility of $131.6 million as of May 29, 2012.

The Facility contains financial covenants, which, among other things, set a maximum ratio of debt to earnings before interest, income tax, depletion, depreciation, and amortization (EBITDA) of not more than 3.75 to 1, 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, but not limited to, restrictions on the Company’s ability to make any dividends, distributions or redemptions.  As of March 31, 2012, the Company is in compliance with the financial debt covenants set forth in the credit agreement.

The Company believes the carrying amount of the Facility approximates its fair value (Level 2) due to the variable nature of the applicable interest rate.

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7. Mandatorily Redeemable Convertible Preferred Units

Pursuant to the Company’s amended and restated limited liability company agreement, as further amended in March 2012, the Company was permitted to issue up to 65,000 in Preferred Units, or $65.0 million in aggregate value, 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% plus the greater of LIBOR or 1.5%. The Preferred Units were convertible on or after the one year anniversary of the date of issuance into a number of common units with a fair market value (as determined by the Board of Directors) equal to the liquidation value plus any accrued interest and were redeemable for cash at any time at the option of the Company, 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 upon redemption or conversion.

On January 4, 2012, and again on February 9, 2012, the Company issued 20,000 Preferred Units (for a total of 40,000 Preferred Units) to FR Midstates for aggregate cash proceeds of $40.0 million.

At March 31, 2012, these issuances remain outstanding. Due to the mandatory redemption feature, these Preferred Units are classified as a liability in the Company’s condensed consolidated balance sheet as of March 31, 2012. The Company recorded $0.8 million related to interest expense associated with these Preferred Units for the three months ended March 31, 2012, which is included in “Mandatorily redeemable convertible preferred units” in the Company’s condensed consolidated balance sheets.

The Company believes the carrying amount of the Preferred Units approximates its fair value (Level 2) due to the recent issuance date and the variable component of the applicable interest rate.

On April 3, 2012, the Company issued an additional 25,000 preferred units to FR Midstates for aggregate cash proceeds of $25.0 million.

Our initial public offering closed on April 25, 2012. On April 26, 2012, using a portion of the $215.6 million in proceeds from our initial public offering, we redeemed the Preferred Units in full in the amount of $67.1 million, including interest and other charges.

8. Members’ Equity and Share-Based Compensation

Common Units

At December 31, 2011, the Company had 256,742 common units issued and outstanding. During the three months ended March 31, 2012, no units were issued or retired, resulting in 256,742 common units issued and outstanding at March 31, 2012.

Share-Based Compensation

During the three months ended March 31, 2011, certain restricted and unrestricted shares in Petroleum Inc., certain unrestricted units in the Company, and certain units in Midstates Incentive Holdings, LLC (“Midstates Incentive”) had been issued to employees of the Company.  Additionally, in March 2011, the Company’s Chief Executive Officer, in connection with the commencement of his employment, purchased 17.3 shares of common stock of Petroleum Inc. and contemporaneously received a grant of 24.6 shares of common stock in Petroleum Inc. that vested as described further below.  The Company determined the grant date fair value of the share based award to be $80,013 per Petroleum Inc. share ($3.4 million in aggregate), or after taking into account the corporate reorganization attributable to the initial public offering completed on April 25, 2012, $4.26 per share of MPCI common stock.  The Company recognized stock compensation in accordance with ASC Topic 718, “Compensation — Stock Compensation” based upon the grant date fair value and immediately expensed the difference between the grant date fair value and the price paid for the purchased shares of Petroleum Inc., as well as additional compensation expense related to the liability accounting for the Company’s share-based awards discussed below.

Prior to December 5, 2011, due to certain rights to call shares and units in the Company for cash, the Company’s share-based payments awarded to employees were accounted for as liability awards pursuant to ASC Topic 718, “Compensation — Stock Compensation.” As such, the Company calculated the fair value of the share-based awards on a quarterly basis using the Company’s estimated market value and the total fair value of the awards was recorded within “Other long-term liabilities” in the Company’s condensed consolidated balance sheets. Any change in the fair value of the liability awards was recorded as share-based compensation expense within “General and administrative expense” in the Company’s condensed consolidated statements of operations, which was the same line item as cash compensation paid to the same employees.

Historically, the Company’s determination of the fair value of each of the units was affected by: i) the Company’s risk adjusted proved, possible, and probable reserves; ii) internal assessment of long-term commodity prices; iii) current values of the Company’s non-oil and gas assets and liabilities; and iv) a number of complex and subjective variables. Although the fair value of the share-based

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payments is determined in accordance with 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 “Effective Date”), the Board of Directors of Petroleum Inc. accelerated the vesting of all restricted stock in Petroleum Inc. The vesting resulted in the recognition of previously unrecognized share-based compensation expense at the estimated fair market value of the restricted stock held by employees at the Effective Date. Petroleum Inc. determined the fair market value of Petroleum Inc.’s common stock based on management’s estimates.

On December 5, 2011, Employment Agreements with employees of Subsidiary, a Stockholders’ Agreement by and among stockholders in Petroleum Inc. and a Unitholders’ Agreement by and among the members of the Company were either terminated or amended such that the rights within those agreements to call shares and units in the Company for cash no longer required the Company’s share-based payments awarded to employees to be accounted for as liability awards.  As a result the Company transitioned as of December 5, 2011 from liability accounting to equity accounting for the Company’s share-based compensation plans and accordingly, the Company no longer recognizes changes in the estimated fair value of outstanding share-based awards in the statements of operations.

During the three months ended March 31, 2012, there were no issuances of shares in Petroleum Inc. or units in the Company or Midstates Incentive.  At December 31, 2011 and March 31, 2012, none of the outstanding shares in Petroleum Inc. or units in the Company or Midstates Incentive were subject to vesting or other performance based conditions.

The following table summarizes share-based compensation expense recognized by the Company for shares in Petroleum Inc. and the Company’s common units and units in Midstates Incentive for the periods presented (in thousands):

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 terminated on the fifth anniversary or upon certain changes in control of the Company, including but not limited to mergers, acquisitions, or a public offering (a “Triggering Event”).

As a result of the vesting discussed above, there is no unrecognized compensation cost and there are no outstanding restricted shares in Petroleum Inc. as of March 31, 2012.

Unrestricted Shares and Units.

Unrestricted shares and Company units are purchased by the recipient on the grant date and are fully vested upon purchase, or represent restricted shares which have vested. For shares and Company units purchased, any difference between the recipient’s purchase price and the grant date fair value is recognized as compensation expense on the grant date.

Incentive Units.

At March 31, 2012, 1,659 incentive units were issued and outstanding. In connection with the corporate reorganization that occurred immediately 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 percentage interest in the amounts distributed to FRMI in excess of certain multiples of FRMI’s aggregate capital contributions and investment expenses (“FRMI Profits”). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FRMI and not by the Company, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the FRMI incentive units. To date, no compensation expense related to the incentive units has been recognized by the Company, as any payout under the incentive units is not considered probable, and thus, the amount of FRMI Profits, if any, cannot be determined.

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9. Related Party Transactions

At March 31, 2012, a minority owner of Petroleum Inc. was also a significant owner of one of the Company’s vendors. For the three months ended March 31, 2012 and March 31, 2011, the amount incurred to this vendor was $0.7 million and $0.3 million, respectively. The amount payable at March 31, 2012 and December 31, 2011 was $0.5 million and $0.1 million, respectively.

10. Commitments and Contingencies

Contractual Obligations

At March 31, 2012, contractual obligations for drilling contracts, long-term operating leases and seismic contracts are as follows (in thousands):

For the three months ended March 31, 2012 and 2011, the Company expensed $0.4 million and $0.2 million, respectively, for office rent.

Litigation

The Company is a defendant in an action brought by Clovelly Oil Company (the “Plaintiff”) in the 13th Judicial District Court in Louisiana in May 2009. The plaintiff alleges that the Company is subject to an unrecorded Joint Operating Agreement (“JOA”) dated July 16, 1972, as a result of the Company’s 2007 purchase of a 43.75% working interest in certain acreage. The Plaintiff alleges that the Company is bound by the 1972 JOA and that the Plaintiff is entitled to 56.25% of the Company’s 242.28-acre Crowell Land & Mineral lease. The Company was not a party to the JOA, and believes that it is protected by the Louisiana Public Records Doctrine, which generally holds that instruments involving real property are without effect as to third parties unless the instrument is filed of record in the appropriate mortgage or conveyance records of the parish in which such property is located.

The Company made a motion for summary judgment on all of the Plaintiff’s claims, and the 13th Judicial District Court granted that motion on August 14, 2009. The Plaintiff appealed the district court’s decision to the Third Circuit Court of Appeal, and on April 7, 2010, the Third Circuit Court of Appeal reversed and remanded the case back to the district court for trial. On August 9, 2010, the Plaintiff amended its original petition to add Wells Fargo Bank, National Association, which holds a mortgage on the acreage as a defendant.

In December 2010, the Company filed a Motion for Partial Summary Judgment asking the district court to declare that the JOA does not apply to any new leases acquired after July 16, 1972 which are not extension or renewal leases. On September 27, 2011, the district court granted the Company’s motion for partial summary judgment. The district court also granted a motion for summary judgment filed by Wells Fargo Bank, National Association asserting that, as a mortgage holder of a mortgage covering the applicable lease, Wells Fargo Bank, National Association is protected by the Public Records Doctrine.

On October 17, 2011, the Plaintiff filed an appeal to the Third Circuit Court of Appeal. Oral arguments were heard by the Third Circuit Court of Appeal on May 1, 2012, and its ruling is expected by June 15, 2012.

The Company does not believe the ultimate outcome of this case will result in a material impact on its financial position, results of operations or cash flows.

We are involved in other disputes or legal actions arising in the ordinary course of our business. We do not believe the outcome of such disputes or legal actions will result in a material impact on our financial position, results of operations, or cash flows.

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11. Subsequent Events

Initial Public Offering

The Reorganization

On April 24, 2012, in connection with our initial public offering, a corporate reorganization (the “Reorganization”) occurred, and each unit of the Company was converted into approximately 185 of our common shares and each Petroleum Inc. share was converted into approximately 18,762 of our common shares.  We issued a total of 47,634,353 of our common shares as a result of the Reorganization and Midstates Petroleum Company LLC became our wholly-owned subsidiary.

On April 25, 2012, we completed our initial public offering.  Our net proceeds from the sale of 18,000,000 common shares in our initial public offering, after underwriting discounts and commissions, was approximately $220.0 million (or $215.6 million after further reducing for estimated offering expenses paid directly by us).  We used approximately $67.1 million of the net proceeds that we received to redeem the Preferred Units, including interest and other charges, and approximately $99.0 million to repay a portion of the borrowings under the Facility.

Additionally, certain affiliates of First Reserve and employees of the Company (the “Selling Stockholders”) sold 6,000,000 shares of our common stock in a secondary offering.  We granted the underwriters a 30-day option to purchase up to an additional 3,600,000 common shares from the Selling Stockholders, and such option was exercised on April 25, 2012.  We did not receive any of the proceeds from the sale of shares by the Selling Stockholders.  Immediately after the initial public offering and exercise of the option, First Reserve or its affiliates own approximately 41.4% of our outstanding common stock.

Immediately after the Reorganization and the initial public offering, a total of 65,634,353 common shares of MPCI were issued and outstanding.

Tax Effect of the Reorganization

The Reorganization was a tax-free event to participants (other than for any cash received by the Selling Shareholders).  As a result of the Reorganization, the Company became a tax paying entity.  As such, we are required to record a charge to income in an amount equal to the tax effect of the excess of the book carrying value of the net assets contributed (primarily producing oil and gas properties) over their collective tax bases.  We currently estimate this charge, which will be recorded in the second quarter of 2012, to be in the range of $150 million to $160 million.

Additionally, we will record income tax expense (benefit) on reported income beginning with the effective date of the Reorganization, or April 25, 2012.  We currently estimate our 2012 effective tax rate (before the charge against earnings discussed above resulting from the Reorganization) will be approximately 50%.  This estimate will be revised quarterly based upon our expected income for the year as required by US GAAP.  The primary differences between our estimated annual effective tax rate and the U.S. statutory rate of 35% are: (i) state income taxes (net of federal benefit) of 5.2%, and (ii) the tax effect of our pre-Reorganization loss that passes through to the Company’s members.

Restricted Stock Awards

In conjunction with our initial public offering, our board of directors approved the Midstates Petroleum Company, Inc. 2012 Long Term Incentive Plan. On April 20, 2012, we filed a Form S-8 with the SEC, which registered 6,563,435 shares for future issuance under the terms of the 2012 Long Term Incentive Plan (“LTIP”).  Shares granted under the LTIP vest ratably over a period of three years (one-third on each anniversary of the grant).

On April 25, 2012, we granted 785,979 restricted shares under the LTIP to certain employees and non-employee directors.  The restricted shares have a grant date fair value of $13.00 per MPCI common share, for a total value of approximately $10.2 million.

On May 23, 2012, we granted 110,515 additional shares of restricted stock under the LTIP to certain employees, with an average grant date fair value based upon the closing price on the date of the grant of $15.02 per MPCI common share, for a total value of approximately $1.7 million.

New Commodity Hedges

In May 2012, MPCI entered into additional commodity hedges covering a portion of its 2013 crude oil production. The following is a summary of these additional hedging arrangements as of May 29, 2012:

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Item 2. — 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 consolidated financial statements and notes thereto for the year ended December 31, 2011, and the related management’s discussion and analysis contained in our final prospectus dated April 19, 2012 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b) on April 20, 2012, as well as the unaudited condensed consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q. In this Quarterly Report on Form 10-Q, the terms “we,” “us,” and “our” refer to Midstates Petroleum Company, Inc. and the term “Company” refers to Midstates Petroleum Holdings LLC.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this quarterly 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. In particular, the factors discussed in this report on Form 10-Q and detailed in our prospectus dated April 19, 2012 and filed with the SEC pursuant to Rule 424(b) on April 20, 2012, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Forward-looking statements may include statements about our:

·                  business strategy;

·                  reserves;

·                  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;

·                  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;

·                  property acquisitions;

·                  costs of developing our properties and conducting other operations;

·                  general economic conditions;

·                  effectiveness of our risk management activities;

·                  environmental liabilities;

·                  counterparty credit risk;

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

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

·                  uncertainty regarding our future operating results;

·                  estimated future net reserves and present value thereof; and

·                  plans, objectives, expectations and intentions contained in this prospectus that are not historical.

All forward-looking statements speak only as of the date of this quarterly 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. 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

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make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this quarterly 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.

Overview

Midstates Petroleum Company, Inc. (“MPCI”) 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, a wholly-owned subsidiary of Midstates Petroleum Holdings LLC (“the Company”).  Pursuant to the terms of a corporate reorganization that was completed immediately prior to the closing of MPCI’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 MPCI,  and as a result, Midstates Petroleum Company LLC became a wholly-owned subsidiary of MPCI.

As of the date of the unaudited financial statements included in this Quarterly Report on Form 10-Q for the three month period ended March 31, 2012, the corporate reorganization referred to above had not occurred and operations were conducted through Midstates Petroleum Holdings LLC and its consolidated subsidiary, Midstates Petroleum Company LLC.  Therefore, the unaudited financial statements included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2012 are those of Midstates Petroleum Holdings LLC and its consolidated subsidiary, Midstates Petroleum Company LLC.

With the completion of our initial public offering, we became a publicly traded company, the common stock of which is listed on the NYSE under the ticker symbol “MPO.”

We are an independent exploration and production company focused on the development of oil-prone resources in the Upper Gulf Coast Tertiary trend onshore in central Louisiana. Our current acreage positions and evaluation efforts are concentrated in the Wilcox interval of the trend. We are currently focused on the development of our inventory of identified drilling locations, which we will selectively allocate capital to by applying rigorous investment analysis in an effort to maximize our potential returns. We are focused on maximizing the net present value of our drilling opportunities by measuring risk and financial return, among other factors. In addition, we are the operator of the substantial majority of our properties, which enables us to better control timing, costs and drilling and completion techniques.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital resources in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity, constraints, inventory storage levels, basis differentials, and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Average Daily Production

As of March 31, 2012, our properties consisted of approximately 110 gross active producing wells, 95% of which we operate, and in which we held an average working interest of approximately 97%.

During the three months ended March 31, 2012, our average daily production was 8,275 Boe/d, which was below our average daily production for the fourth quarter of 2011 of 9,433 Boe/d primarily due to the decline of two wells from our South Bearhead Creek/Oretta operating area and the postponement of drilling activity in 2012 due to delays in completing our initial public offering and our receipt of the related funding.

Drilling Program

Since December 31, 2011, we continued to execute our drilling program, spudding fourteen gross wells during the three months ended March 31, 2012, of which nine were producing, two were awaiting completion and three were drilling at quarter end. Since March 31, 2012, we have spud twelve additional wells.  Our first horizontal well in the Upper Gulf Coast Tertiary trend was drilled in the fourth quarter of 2011, and technical lessons learned are being applied to subsequent horizontal projects.  A second horizontal well was successfully completed in early May 2012, and a third horizontal well was recently completed.  Early results from both of these wells are encouraging and support the application of horizontal drilling in the trend.  We plan to execute a total of twelve horizontal projects during 2012.

The delay in completing our initial public offering temporarily slowed the planned ramp-up in drilling activity.  We now expect to spud 76 wells in 2012 with the same capital budget of $380 million, with drilling activity weighted towards the second half of the year.  Six rigs are currently deployed, including one smaller, less costly rig that is utilized in our shallow well drilling program up from four rigs as of the beginning of 2012. We plan to add an additional rig to our shallow well program in the near future and we expect to add another rig that will be utilized in developing our Wilcox and other deeper sand by the 2012 fourth quarter. Our plans for 2012 drilling by area include:  forty-two wells in Pine Prairie, twelve wells in South Bearhead Creek, seven wells in West Gordon, two wells in North Cowards Gully, and thirteen wells in the Company’s expansion areas.

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Capital Expenditures

During the three months ended March 31, 2012, we incurred capital expenditures of $97.8 million, consisting primarily of $72.1 million in drilling and completion activities, approximately $17.6 million for acquisition of acreage and seismic data, and approximately $8.1 million for facilities. This represents approximately 26% of the total capital expenditures budget for 2012 of $380 million.

Through May 29, 2012, we also increased our acreage in the trend to approximately 151,200 total net acres, comprised of approximately 101,400 net leased acres and approximately 49,800 net optioned acres, an increase of 39% in total net acres since December 31, 2011.

Factors that Significantly Affect our Results

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

We generally hedge a portion of our expected future oil and gas production to reduce our exposure to fluctuations in commodity price. By removing a portion of commodity price volatility, we expect to reduce some of the variability in our cash flow from operations. See “Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Exposure” beginning on page 22 for discussion of our hedging and hedge positions.

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on the capital investments necessary to produce our reserves as well as to add to our reserves through drilling and acquisition. Our ability to make the necessary capital expenditures is dependent on cash flow from operations as well as our ability to obtain additional debt and equity financing. That ability can be limited by many factors, including the cost of such capital and operational considerations.

The volumes of oil and natural gas that we produce are driven by several factors, including:

·                  success in the drilling of new wells, including exploratory wells, and the recompletion of

·                  existing wells;

·                  the amount of capital we invest in the leasing and development of our oil and natural gas properties;

·                  facility or equipment availability and unexpected downtime;

·                  delays imposed by or resulting from compliance with regulatory requirements; and

·                  the rate at which production volumes on our wells naturally decline.

Results of Operations

The following table summarizes our revenues and production data for the period indicated (in thousands, except production amounts and average sales prices):

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