XNYS:MPO Midstates Petroleum Co Inc Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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Table of Contents

 

 

 

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)

 


 

Delaware

 

45-3691816

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

 

 

4400 Post Oak Parkway, Suite 1900

 

 

Houston, Texas

 

77027

(Address of principal executive offices)

 

(Zip Code)

 

(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):

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer x

 

Smaller reporting company o

 

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:

 

Class

 

Number of shares outstanding

Common stock, $0.01 par value

 

66,420,332

 

 

 



Table of Contents

 

MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2012

 

TABLE OF CONTENTS

 

 

Page

 

 

Glossary of Oil and Natural Gas Terms

i

 

 

PART I - FINANCIAL INFORMATION

 

 

 

Item 1.- Financial Statements

 

Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011 (unaudited)

1

Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011 (unaudited)

2

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011 (unaudited)

3

Notes to Unaudited Condensed Consolidated Financial Statements

4

 

 

Item 2. - Management’s Discussion and Analysis of Financial Condition and Results of Operations

14

 

 

Item 3. - Quantitative and Qualitative Disclosures About Market Risk

22

 

 

Item 4. - Controls and Procedures

23

 

 

PART II - OTHER INFORMATION

 

 

 

Item 1. - Legal Proceedings

24

 

 

Item 1A. - Risk Factors

24

 

 

Item 2. - Unregistered Sales of Equity Securities and Use of Proceeds

24

 

 

Item 3. - Defaults upon Senior Securities

25

 

 

Item 4. - Mine Safety Disclosures

25

 

 

Item 5. - Other Information

25

 

 

Item 6. - Exhibits

25

 

 

SIGNATURES

26

 

 

EXHIBIT INDEX

27

 



Table of Contents

 

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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Table of Contents

 

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.

 

ii



Table of Contents

 

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.

 

iii



Table of Contents

 

PART I - FINANCIAL INFORMATION

 

MIDSTATES PETROLEUM HOLDINGS LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

 

 

 

March 31, 2012

 

December 31, 2011

 

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

9,194

 

$

7,344

 

Accounts receivable:

 

 

 

 

 

Oil and gas sales

 

20,915

 

23,792

 

Severance tax refund

 

580

 

3,413

 

Other

 

335

 

249

 

Prepayments

 

4,560

 

2,642

 

Inventory

 

6,208

 

5,713

 

Commodity derivative contracts

 

517

 

4,957

 

Total current assets

 

42,309

 

48,110

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT:

 

 

 

 

 

 

 

 

 

 

 

Oil and gas properties, on the basis of full-cost accounting:

 

 

 

 

 

Proved properties

 

730,723

 

644,393

 

Unevaluated properties

 

88,470

 

76,857

 

Other property and equipment

 

1,940

 

1,672

 

 

 

 

 

 

 

Less accumulated depreciation, depletion, and amortization

 

(176,870

)

(148,843

)

Net property and equipment

 

644,263

 

574,079

 

 

 

 

 

 

 

OTHER ASSETS:

 

 

 

 

 

Commodity derivative contracts

 

374

 

588

 

Security deposit and other noncurrent assets

 

1,663

 

1,879

 

Total other assets

 

2,037

 

2,467

 

 

 

 

 

 

 

TOTAL

 

$

688,609

 

$

624,656

 

 

 

 

 

 

 

LIABILITIES AND MEMBERS’ EQUITY

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable

 

$

49,425

 

$

35,731

 

Accrued liabilities

 

50,477

 

37,524

 

Commodity derivative contracts

 

22,816

 

12,599

 

Current portion of long-term debt

 

25,000

 

 

Total current liabilities

 

147,718

 

85,854

 

 

 

 

 

 

 

LONG-TERM LIABILITIES:

 

 

 

 

 

Asset retirement obligations

 

8,206

 

7,627

 

Commodity derivative contracts

 

13,473

 

10,178

 

Long-term debt

 

209,800

 

234,800

 

Mandatorily redeemable convertible preferred units

 

40,762

 

 

Other long-term liabilities

 

655

 

695

 

Total long-term liabilities

 

272,896

 

253,300

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (Note 10)

 

 

 

 

 

 

 

 

 

 

 

MEMBERS’ EQUITY

 

267,995

 

285,502

 

 

 

 

 

 

 

TOTAL

 

$

688,609

 

$

624,656

 

 

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

 

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Table of Contents

 

MIDSTATES PETROLEUM HOLDINGS LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

 

 

 

Three months ended March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

REVENUES:

 

 

 

 

 

Oil sales

 

$

45,082

 

$

35,583

 

Natural gas sales

 

3,450

 

4,073

 

Natural gas liquid sales

 

6,272

 

2,045

 

Losses on commodity derivative contracts — net

 

(24,665

)

(28,596

)

Other

 

105

 

54

 

 

 

 

 

 

 

Total revenues

 

30,244

 

13,159

 

 

 

 

 

 

 

EXPENSES:

 

 

 

 

 

Lease operating and workover

 

6,467

 

2,606

 

Severance and other taxes

 

5,376

 

4,124

 

Asset retirement accretion

 

134

 

47

 

General and administrative

 

6,064

 

3,904

 

Depreciation, depletion, and amortization

 

28,027

 

18,618

 

 

 

 

 

 

 

Total expenses

 

46,068

 

29,299

 

 

 

 

 

 

 

OPERATING LOSS

 

(15,824

)

(16,140

)

 

 

 

 

 

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

Interest income

 

7

 

8

 

Interest expense — net of amounts capitalized

 

(1,690

)

 

 

 

 

 

 

 

Total other income (expense)

 

(1,683

)

8

 

 

 

 

 

 

 

NET LOSS

 

$

(17,507

)

$

(16,132

)

 

 

 

 

 

 

Pro forma income tax benefit

 

$

(7,038

)

$

(6,485

)

 

 

 

 

 

 

Pro forma net loss

 

$

(10,469

)

$

(9,647

)

 

 

 

 

 

 

Pro forma basic and diluted loss per share

 

$

(0.16

)

$

(0.15

)

 

 

 

 

 

 

Pro forma basic and diluted weighted average shares outstanding

 

65,634,353

 

65,634,353

 

 

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

 

2



Table of Contents

 

MIDSTATES PETROLEUM HOLDINGS LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

 

 

 

Three months ended March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net loss

 

$

(17,507

)

$

(16,132

)

Adjustments to reconcile net loss to net cash provided by operating activities:

 

 

 

 

 

Unrealized losses on commodity derivative contracts, net

 

18,166

 

26,589

 

Asset retirement accretion

 

134

 

47

 

Depreciation, depletion, and amortization

 

28,027

 

18,618

 

Share-based compensation

 

 

650

 

Accrued interest on mandatorily redeemable convertible preferred units

 

762

 

 

Amortization of deferred financing costs

 

216

 

179

 

Change in operating assets and liabilities:

 

 

 

 

 

Accounts receivable — oil and gas sales

 

2,877

 

(3,455

)

Accounts receivable — other

 

2,747

 

412

 

Prepayments and other assets

 

(1,918

)

(352

)

Inventory

 

(495

)

(77

)

Accounts payable

 

161

 

(7,028

)

Accrued liabilities

 

1,186

 

7,282

 

Other

 

(40

)

(3

)

 

 

 

 

 

 

Net cash provided by operating activities

 

$

34,316

 

$

26,730

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Investment in property and equipment

 

(72,466

)

(52,392

)

 

 

 

 

 

 

Net cash used in investing activities

 

$

(72,466

)

$

(52,392

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Proceeds from long-term borrowings

 

 

18,000

 

Proceeds from issuance of mandatorily redeemable convertible preferred units

 

40,000

 

 

Cash received for units

 

 

170

 

Other

 

 

(300

)

 

 

 

 

 

 

Net cash provided by financing activities

 

$

40,000

 

$

17,870

 

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

1,850

 

(7,792

)

 

 

 

 

 

 

Cash and cash equivalents, beginning of period

 

7,344

 

11,917

 

 

 

 

 

 

 

Cash and cash equivalents, end of period

 

9,194

 

4,125

 

 

 

 

 

 

 

SUPPLEMENTAL INFORMATION:

 

 

 

 

 

Non-cash transactions — investments in property and equipment accrued — not paid

 

$

82,845

 

$

22,100

 

 

 

 

 

 

 

Cash paid for interest, net of capitalized interest of $0.7 million and $0.6 million, respectively

 

$

1,106

 

$

 

 

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

 

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Table of Contents

 

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.

 

 

 

Fair Value Measurements at March 31, 2012

 

 

 

Quoted Prices in Active
Markets
(Level 1)

 

Significant Other
Observable Inputs
(Level 2)

 

Significant Unobservable
Inputs
(Level 3)

 

Total

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

261

 

$

 

$

261

 

Commodity derivative deferred premium puts

 

 

471

 

 

471

 

Commodity derivative collars

 

 

46

 

 

46

 

Commodity derivative differential swaps

 

 

113

 

 

113

 

Total assets

 

 

891

 

 

891

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

31,418

 

$

 

$

31,418

 

Commodity derivative deferred premium puts

 

 

494

 

 

494

 

Commodity derivative collars

 

 

30

 

 

30

 

Commodity derivative differential swaps

 

 

4,347

 

 

4,347

 

Total liabilities

 

$

 

$

36,289

 

$

 

$

36,289

 

 

 

 

Fair Value Measurements at December 31, 2011

 

 

 

Quoted Prices in Active
Markets
(Level 1)

 

Significant Other
Observable Inputs
(Level 2)

 

Significant Unobservable
Inputs
(Level 3)

 

Total

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

 

$

 

$

 

Commodity derivative deferred premium puts

 

 

1,673

 

 

1,673

 

Commodity derivative collars

 

 

397

 

 

397

 

Commodity derivative differential swaps

 

 

4,200

 

 

4,200

 

Total assets

 

 

6,270

 

 

6,270

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

23,162

 

$

 

$

23,162

 

Commodity derivative deferred premium puts

 

 

340

 

 

340

 

Commodity derivative collars

 

 

 

 

 

Commodity derivative differential swaps

 

 

 

 

 

Total liabilities

 

$

 

$

23,502

 

$

 

$

23,502

 

 

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:

 

 

 

Hedged Volume

 

Weighted-Average Fixed
Price

 

 

 

 

 

 

 

Oil (Bbls):

 

 

 

 

 

WTI Swaps – 2012

 

652,250

 

$

84.22

 

WTI Swaps – 2013

 

679,125

 

84.73

 

WTI Swaps – 2014

 

262,450

 

83.00

 

 

 

 

 

 

 

WTI Collars – 2012

 

123,750

 

$

 85.00 - 127.28

 

 

 

 

 

 

 

WTI Deferred Premium Puts – 2012 (1)

 

412,500

 

$

79.01

 

 

 

 

 

 

 

WTI Basis Differential Swaps – 2012 (2)

 

852,500

 

$

9.78

 

WTI Basis Differential Swaps – 2013 (2)

 

182,500

 

7.50

 

 

 

 

 

 

 

LLS Swaps - 2012

 

315,180

 

$

116.55

 

 

 

 

 

 

 

Brent Swaps - 2013

 

1,021,749

 

$

111.89

 

 


(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):

 

Type

 

Balance Sheet Location (1)

 

March 31, 2012

 

December 31, 2011

 

Oil Swaps

 

Derivative financial instruments — Current Assets

 

$

 

$

 

Oil Swaps

 

Derivative financial instruments — Non-Current Assets

 

261

 

 

Oil Swaps

 

Derivative financial instruments — Current Liabilities

 

(17,945

)

(13,046

)

Oil Swaps

 

Derivative financial instruments — Non-Current Liabilities

 

(13,473

)

(10,116

)

Deferred Premium Puts

 

Derivative financial instruments — Current Assets

 

471

 

1,673

 

Deferred Premium Puts

 

Derivative financial instruments — Non-Current Assets

 

 

 

Deferred Premium Puts

 

Derivative financial instruments — Current Liabilities

 

(494

)

(278

)

Deferred Premium Puts

 

Derivative financial instruments — Non-Current Liabilities

 

 

(62

)

Collars

 

Derivative financial instruments — Current Assets

 

46

 

397

 

Collars

 

Derivative financial instruments — Non-Current Assets

 

 

 

Collars

 

Derivative financial instruments — Current Liabilities

 

(30

)

 

Collars

 

Derivative financial instruments — Non-Current Liabilities

 

 

 

Basis Differential Swaps

 

Derivative financial instruments — Current Assets

 

 

3,612

 

Basis Differential Swaps

 

Derivative financial instruments — Non-Current Assets

 

113

 

588

 

Basis Differential Swaps

 

Derivative financial instruments — Current Liabilities

 

(4,347

)

 

Basis Differential Swaps

 

Derivative financial instruments — Non-Current Liabilities

 

 

 

Total

 

 

 

$

(35,398

)

$

(17,232

)

 


(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):

 

 

 

March 31, 2012

 

December 31, 2011

 

Consolidated balance sheet classification:

 

 

 

 

 

Current derivative instruments:

 

 

 

 

 

Assets

 

$

517

 

$

4,957

 

Liabilities

 

(22,816

)

(12,599

)

 

 

 

 

 

 

Non-current derivative instruments :

 

 

 

 

 

Assets

 

$

374

 

$

588

 

Liabilities

 

(13,473

)

(10,178

)

 

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):

 

Asset retirement obligations at January 1, 2012

 

$

7,627

 

Liabilities incurred

 

442

 

Revisions

 

3

 

Liabilities settled

 

 

Current period accretion expense

 

134

 

Asset retirement obligations at March 31, 2012

 

$

8,206

 

 

6. Long-Term Debt

 

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

 

 

 

March 31, 2012

 

December 31, 2011

 

Credit Facility — senior loan facility

 

$

234,800

 

$

234,800

 

Less: current maturities of debt

 

(25,000

)

 

 

 

$

209,800

 

$

234,800

 

 

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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Table of Contents

 

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):

 

 

 

Three Months
Ended March 31,
2012

 

Three Months
Ended March 31,
2011

 

Restricted and unrestricted shares and units

 

$

 

$

650

 

Incentive units

 

 

 

 

 

$

 

$

650

 

 

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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Table of Contents

 

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):

 

 

 

Total

 

2012
(remainder)

 

2013

 

2014

 

2015

 

2016 and
beyond

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drilling contracts

 

$

5,659

 

5,659

 

 

 

 

 

Non-cancellable office lease commitments

 

$

1,728

 

652

 

860

 

216

 

 

 

Seismic contracts

 

$

21,749

 

21,249

 

500

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net minimum commitments

 

$

29,136

 

$

27,560

 

$

1,360

 

$

216

 

$

 

$

 

 

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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Table of Contents

 

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:

 

 

 

Hedged Volume

 

Weighted-Average Fixed
Price

 

 

 

 

 

 

 

Oil (Bbls):

 

 

 

 

 

WTI Basis Differential Swaps — 2013

 

496,625

 

$

5.86

 

 

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Table of Contents

 

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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Table of Contents

 

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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Table of Contents

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

REVENUES:

 

 

 

 

 

Oil sales

 

$

45,082

 

$

35,583

 

Natural gas sales

 

3,450

 

4,073

 

Natural gas liquid sales

 

6,272

 

2,045

 

Unrealized losses on commodity derivative contracts

 

(18,166

)

(26,589

)

Realized losses on commodity derivative contracts

 

(6,499

)

(2,007

)

Other

 

105

 

54

 

 

 

 

 

 

 

Total revenues

 

30,244

 

13,159

 

 

 

 

 

 

 

EXPENSES:

 

 

 

 

 

Lease operating and workover

 

6,467

 

2,606

 

Severance and other taxes

 

5,376

 

4,124

 

Asset retirement accretion

 

134

 

47

 

General and administrative

 

6,064

 

3,904

 

Depreciation, depletion, and amortization

 

28,027

 

18,618

 

 

 

 

 

 

 

Total expenses

 

46,068

 

29,299

 

 

 

 

 

 

 

OPERATING LOSS

 

(15,824

)

(16,140

)

 

 

 

 

 

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

Interest income

 

7

 

8

 

Interest expense — net of amounts capitalized

 

(1,690

)

 

 

 

 

 

 

 

Total other income (expense)

 

(1,683

)

8

 

 

 

 

 

 

 

NET LOSS

 

$

(17,507

)

$

(16,132

)

 

 

 

 

 

 

PRODUCTION DATA:

 

 

 

 

 

Oil (MBbls)

 

405

 

361

 

Natural gas (MMcf)

 

1,322

 

881

 

Natural gas liquids (MBbls)

 

127

 

47

 

Oil equivalents (MBoe)

 

753

 

556

 

 

 

 

 

 

 

Average daily production (Boe/d)

 

8,275

 

6,173

 

 

 

 

 

 

 

AVERAGE SALES PRICES:

 

 

 

 

 

Oil, without realized derivatives (per Bbl)

 

$

111.21

 

$

98.44

 

Oil, with realized derivatives (per Bbl)

 

$

95.18

 

$

92.88

 

Natural gas (per Mcf)

 

$

2.61

 

$

4.62

 

Natural gas liquids (per Bbl)

 

$

49.23

 

$

43.32

 

 

Three Months Ended March 31, 2012 as Compared to the Three Months Ended March 31, 2011

 

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and natural gas liquids (“NGL”) sales revenues increased by $13.1 million, or 31%, to $54.8 million during the first quarter of 2012 as compared to $41.7 million for the first quarter of 2011. Our revenues are a function of oil, natural gas, and NGLs production volumes sold and average sales prices received for those volumes. Of the $13.1 million revenue variance, sales volume increases contributed $9.8 million of the total, while price variance contributed $3.3 million. Average daily production sold increased by 2,102 Boe per day, or 34%, to 8,275 Boe per day during the first quarter of 2012 as compared to 6,173 Boe per day during the first quarter of 2011. The increase in average daily production sold was primarily due to a greater number of producing wells during the 2012 period resulting from our increased drilling activity. Average oil sales prices, without realized derivatives, increased by $12.77 per barrel or 13% to $111.21 per barrel for the first quarter of 2012 as compared to $98.44 per barrel for the first quarter of 2011.

 

Losses on commodity derivative contracts - net. Our mark-to-market (“MTM”) derivative positions moved from an unrealized loss of $26.6 million in the first quarter of 2011 to an unrealized loss of $18.2 million in the first quarter of 2012. The realized loss on derivatives for the three months ended March 31, 2012 was $6.5 million compared to a realized loss of $2.0 million for the three months ended March 31, 2011. Realized oil sales prices, with realized derivatives, averaged $95.18 per barrel for the first quarter of 2012 compared to $92.88 per barrel for the same period in 2011.

 

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Lease operating and workover expenses. Lease operating and workover expenses increased $3.9 million, or 148%, to $6.5 million for the first quarter of 2012 compared to $2.6 million for the first quarter of 2011. This increase was primarily due to higher salt water disposal costs of $0.9 million, additional surface maintenance costs of $0.6 million due to increased road and lease maintenance, additional well work charges and chemical costs of $0.6 million due to a greater number of producing wells period over period, with the remaining variance primarily attributable to increases in labor related and environmental and safety costs. We also completed nine workovers in the first quarter of 2012, which was an increase of six projects over the three workovers completed in the first quarter of 2011.  Lease operating and workover expenses increased to $8.59 per Boe at March 31, 2012 from $4.69 per Boe at March 31, 2011, an increase of 83%, which was primarily a result of the increases in lease operating and workover expenses noted above, without a proportionate increase in production across the periods.

 

Severance and other taxes. Severance taxes increased $0.5 million, or 13%, to $4.5 million for the first quarter of 2012 as compared to $4.0 million for the first quarter of 2011. This increase was primarily attributable to higher oil, natural gas and NGLs sales revenue during the first quarter of 2012. Our severance taxes as a percentage of oil, natural gas and NGLs sales revenue were 8.2% for the first quarter of 2012, compared to 9.5% in the first quarter of 2011. Ad valorem taxes increased $0.7 million, or 350%, to $0.9 million for the first quarter of 2012 as compared to $0.2 million for the first quarter of 2011, corresponding to a related increase in oil and gas properties during the same periods of approximately 66%.

 

Depreciation, depletion and amortization (DD&A). DD&A expense increased $9.4 million, or 51%, to $28.0 million for the first quarter of 2012 compared to $18.6 million for the first quarter of 2011. The DD&A rate for first quarter of 2012 was $37.22 per Boe compared to $33.49 per Boe for the first quarter of 2011. The increase in DD&A expense for the first quarter of 2012 was primarily due to higher production volumes during the 2012 period, as well as capital expenditures incurred during the 2012 period, without a corresponding proportionate increase in the total proved reserve base.

 

General and administrative. Our general and administrative expenses increased by $2.2 million, or 55%, to $6.1 million for the first quarter of 2012 compared to $3.9 million for the first quarter of 2011. As of March 31, 2012, we had 63 full time employees compared to 43 employees as of March 31, 2011. The 47% increase in headcount resulted in a $1.1 million increase in employee related salary and insurance costs, which contributed to the $2.2 million increase in general and administrative expenses. Also contributing to the $2.2 million increase was an increase in professional fees, primarily relating to accounting and consulting, of $0.5 million, and an increase in rent expense of $0.2 million.

 

Interest expense. Interest expense for the three months ended March 31, 2012 and for the three months ended March 31, 2011 was $2.4 million and $0.6 million, respectively. The increase in interest expense is primarily due to the increase in outstanding balances under our revolving credit facility, which increased from $107.6 million at March 31, 2011 to $234.8 million at March 31, 2012, and relates to $1.6 million of the total interest expense of $2.4 million. The remainder of the interest expense for the three months ended March 31, 2012, $0.8 million, related to interest expense associated with our outstanding Preferred Units, which were not outstanding during the three months ended March 31, 2011. Of total interest expense, $0.7 million and $0.6 million was capitalized, resulting in $1.7 million and no interest expense for the three months ended March 31, 2012 and March 31, 2011, respectively.

 

Liquidity and Capital Resources

 

The following table presents our liquidity and financial position as of March 31, 2012 and May 29, 2012 (in thousands):

 

 

 

March 31, 2012

 

May 29, 2012

 

Cash

 

$

9,194

 

$

12,246

 

Unused borrowing base under the revolving credit facility

 

 

78,167

(1)

 

 

 

 

 

 

Total liquidity

 

$

9,194

 

$

90,413

 

 


(1)          After application of repayments of $4.2 million on April 20, 2012 and $99.0 million from the net proceeds from our initial public offering on April 25, 2012.

 

Historically, our primary sources of liquidity have been equity provided by First Reserve and our management team, borrowings under our revolving credit facility and cash flows from operations. Our primary use of capital has been the acquisition, exploration and development of oil and natural gas properties.

 

Upon completion of our reorganization and initial public offering as discussed further below, our primary sources of future capital are anticipated to be borrowings under our revolving credit facility and cash flows from operations.   Additionally, MPCI is authorized to issue up to an aggregate of 50,000,000 shares of MPCI preferred stock, par value $0.01 per share, the number and terms of which are

 

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subject to determination by the board of directors, and up to a total of 300,000,000 in MPCI common stock, which could provide additional sources of capital, if market conditions are favorable.  We continually monitor potential capital sources, including equity and debt capital markets, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.  We believe that our available cash, together with the net proceeds from our initial public offering, anticipated future cash flows from operations and borrowings under our revolving credit facility will be sufficient to meet our operating needs through 2013.

 

Significant Sources of Capital

 

Reserve-based Credit Facility

 

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.

 

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 revolving credit facility, we are required to repay the amount by which the principal balance of our outstanding loans and our letter of credit obligations exceed our redetermined borrowing base. Under the terms of the revolving credit facility, we are permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice to us regarding such borrowing base reduction. At March 31, 2012, as a result of the March 2012 redetermination that reduced our 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 our 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 $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, leaving 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.

 

Mandatorily Redeemable Convertible Preferred Units

 

Pursuant to the 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) 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 remained 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.

 

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 the initial public offering, we redeemed the Preferred Units in full in the amount of $67.1 million, including interest and other charges.

 

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Upon the completion of the reorganization in connection with our initial public offering, preferred units are no longer issuable under this agreement.

 

Initial Public Offering

 

On April 25, 2012, we completed our initial public offering.  Our estimated net proceeds from the sale of 18,000,000 of our common shares in the initial public offering, after underwriting discounts and commissions, was approximately $220.0 million (or $215.6 million after estimated offering expenses paid directly by us).  Approximately $67.1 million of the net proceeds received by MPCI were used to redeem the Preferred Units, including interest and other charges, and approximately $99.0 million was used to pay down a portion of our borrowings under the Facility.  The remaining proceeds were retained to fund the execution of our growth strategy through our drilling program.

 

Cash Flows from Operating, Investing and Financing Activities

 

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods presented (dollars in thousands). For information regarding the individual components of our cash flow amounts, please refer to the Unaudited Condensed Consolidated Statements of Cash Flows included under Item 1 of this quarterly report.

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

34,316

 

$

26,730

 

Net cash used in investing activities

 

(72,466

)

(52,392

)

Net cash provided by financing activities

 

40,000

 

17,870

 

 

 

$

1,850

 

$

(7,792

)

 

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 3. — Quantitative and Qualitative Disclosures About Market Risk” beginning on page 22.

 

The following information highlights the significant quarter-to-quarter variances in our cash flow amounts:

 

Cash flows provided by operating activities.

 

Net cash provided by operating activities was $34.3 million and $26.7 million for the three months ended March 31, 2012 and March 31, 2011, respectively. The increase in net cash provided by operating activities was primarily the result of an increase in oil and NGLs production as well as an increase in realized oil prices.

 

Cash flows used in investing activities

 

We had net cash used in investing activities of $72.5 million and $52.4 million during the three months ended March 31, 2012 and March 31, 2011, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The increase in net cash used in investing activities during first quarter of 2012 compared to first quarter of 2011 is attributable to continued expansion of our drilling programs and growth of our business.

 

Capital Expenditures

 

As of March 31, 2012 our total capital expenditure budget for 2012 is $380 million, which consists of:

 

·                  $304 million for drilling and completion capital;

·                  $58 million for acquisition of acreage and seismic data; and

·                  $18 million in unallocated funds which are available for facilities.

 

Through March 31, 2012, approximately $97.8 million of our 2012 capital expenditure budget had been incurred.

 

While we have budgeted $380 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions, our ability, if necessary, to access additional funding through debt or equity markets on favorable terms, our borrowing availability under the Facility and the success of our drilling results as the year progresses.

 

20



Table of Contents

 

Cash flows provided by financing activities

 

Net cash provided by financing activities was $40.0 million and $17.9 million for the three months ended March 31, 2012 and March 31, 2011, respectively. For these periods, cash sourced through financing activities was provided primarily by First Reserve and members of our management and borrowings under our revolving credit facility. Our outstanding amount under the revolving credit facility was $234.8 million at March 31, 2012.

 

Critical Accounting Policies and Estimates

 

A discussion of our critical accounting policies and estimates is included in Midstates Petroleum Company, Inc.’s Registration Statement on Form S-1, as amended (Registration No. 333-177966). There have been no material changes to those policies.

 

When used in the preparation of our condensed consolidated financial statements, estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our condensed consolidated financial position, results of operations and cash flows.

 

Other Items

 

Contractual Obligations

 

The following table summarizes our contractual obligations as of March 31, 2012 (in thousands):

 

 

 

Payments due by Period (1)

 

 

 

Total

 

Less than 1
year

 

1-3 years

 

3-5 years

 

More than 5
years

 

Revolving credit facility (2)

 

$

234,800

 

25,000

 

209,800

 

 

 

Operating leases (3)

 

$

1,728

 

652

 

1,076

 

 

 

Drilling contracts (3) (4)

 

$

5,659

 

5,659

 

 

 

 

Seismic contracts (3)

 

$

21,749

 

21,249

 

500

 

 

 

Asset retirement obligations (5)

 

$

8,206

 

 

 

 

8,206

 

Total contractual obligations

 

$

272,142

 

$

52,560

 

$

211,376

 

$

 

$

8,206

 

 


(1)          Less than 1 year represents amounts for the remainder of 2012 (April 1 through December 31), 1-3 years represents amounts for 2013 and 2014, 3-5 years represents amounts for 2015 and 2016, and more than 5 years represents amounts after 2016.

(2)          The Company repaid $4.2 million on April 20, 2012 and $99.0 million from the net proceeds from the initial public offering on April 25, 2012.

(3)          See Note 10 in the Notes to the Unaudited Condensed Consolidated Financial Statements for a description of operating lease, drilling contract, and seismic contract obligations.

(4)          The Company entered into agreements after March 31, 2012 which will require additional minimum payments of approximately $2.0 million during the remainder of 2012 for certain drilling contracts.

(5)          Amounts represent our estimate of future asset retirement obligations on an undiscounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 5 in the Notes to the Unaudited Condensed Consolidated Financial Statements.

 

At March 31, 2012, the Company had $40.8 million (including accrued interest) in mandatorily redeemable convertible preferred units due June 2015 outstanding. On April 3, 2012, we issued an additional 25,000 preferred units for aggregate cash proceeds of $25.0 million. On April 26, 2012, utilizing a portion of our proceeds from the initial public offering, we redeemed the units in full in the amount of $67.1 million, including interest.

 

21



Table of Contents

 

Off-Balance Sheet Arrangements

 

We do not currently have any off-balance sheet arrangements.

 

Related Party Transactions

 

With respect to related party transactions, see Note 9 in the Notes to the Unaudited Condensed Consolidated Financial Statements.

 

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 our condensed consolidated financial statements.

 

Item 3. — Quantitative and Qualitative Disclosures About Market Risk

 

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.

 

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses or gains, but rather indicators of reasonably possible losses or gains. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. These derivative instruments are discussed in “Item 1.—Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements — Note 4. Risk Management and Derivative Instruments.”

 

Commodity Price Exposure. We are exposed to market risk as the prices of oil and natural gas fluctuate due to changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we have hedged in the past and expect to hedge a significant portion of our future production.

 

We utilize derivative financial instruments to manage risks related to changes in oil prices. As of March 31, 2012, we utilized fixed price swaps, collars, deferred-premium puts and basis differential swaps to reduce the volatility of oil prices on a portion of our future expected oil production.

 

For derivative instruments recorded at fair value, the credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet.

 

The following is a summary of our commodity derivative contracts as of March 31, 2012:

 

 

 

Hedged Volume

 

Weighted-Average Fixed
Price

 

 

 

 

 

 

 

Oil (Bbls):

 

 

 

 

 

WTI Swaps — 2012

 

652,250

 

$84.22

 

WTI Swaps — 2013

 

679,125

 

84.73

 

WTI Swaps — 2014

 

262,450

 

83.00

 

 

 

 

 

 

 

WTI Collars — 2012

 

123,750

 

$85.00 - 127.28

 

 

 

 

 

 

 

WTI Deferred Premium Puts — 2012 (1)

 

412,500

 

$79.01

 

 

 

 

 

 

 

WTI Basis Differential Swaps — 2012 (2)

 

852,500

 

$9.78

 

WTI Basis Differential Swaps — 2013 (2)

 

182,500

 

7.50

 

 

 

 

 

 

 

LLS Swaps - 2012

 

315,180

 

$116.55

 

 

 

 

 

 

 

Brent Swaps - 2013

 

1,021,749

 

$111.89

 

 

22



Table of Contents

 

 

 

Three Months Ended
March 31, 2012

 

 

 

(in thousands)

 

Derivative fair value at period end — liability (included in the balance sheet)

 

$

(35,398

)

 

 

 

 

Realized net (loss) gain (included in the statement of operations)

 

$

(6,499

)

 

 

 

 

Unrealized net (loss) gain (included in the statement of operations)

 

$

(18,166

)

 


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)              We enter into swap arrangements intended to capture the positive differential between LLS pricing and NYMEX WTI pricing.

 

In May 2012, we entered into additional commodity derivative contracts covering a portion of our 2013 crude oil production. The following is a summary of these additional hedging arrangements as of May 29, 2012:

 

 

 

Hedged Volume

 

Weighted-Average Fixed
Price

 

 

 

 

 

 

 

Oil (Bbls):

 

 

 

 

 

WTI Basis Differential Swaps — 2013

 

496,625

 

$

5.86

 

 

At March 31, 2012 and December 31, 2011, all of our commodity derivative contracts were with two bank counterparties. Our policy is to net derivative liabilities and assets where there is a legally enforceable master netting agreement with the counterparty.

 

Interest Rate Risk. At March 31, 2012, we had indebtedness outstanding under our credit facility of $234.8 million, which bore interest at floating rates. The average annual interest rate incurred on this indebtedness for the three months ended March 31, 2012 and March 31, 2011 was approximately 3.1% and 2.5%, respectively. A 1.0% increase in each of the average LIBOR and federal funds rate for the three months ended March 31, 2012 and three months ended March 31, 2011 would have resulted in an estimated $0.6 million and $0.2 million, respectively, increase in interest expense, of which a portion may be capitalized.

 

We may utilize interest rate derivatives to mitigate our exposure to change in interest rates. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

 

Item 4. — Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

During the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures at March 31, 2012 are effective.

 

Changes in Internal Control over Financial Reporting

 

Prior to the completion of our initial public offering, we were a private company with limited accounting personnel to adequately execute our accounting processes and limited other supervisory resources with which to address our internal control over financial reporting. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements. Our independent registered accounting firm and we concluded that these control deficiencies represented a material weakness in internal control over financial reporting for the year ended December 31, 2011.

 

23



Table of Contents

 

During the three months ended March 31, 2012, we have continued to address the causes of this material weakness by putting into place new accounting processes and control procedures, including implementation of disclosure checklists and other reporting tools. In addition, since December 31, 2011, we have added six experienced accounting personnel in response to our identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company.  We believe that these corrective actions have improved our internal controls over financial reporting and remediated the material weakness identified at December 31, 2011.

 

PART II - OTHER INFORMATION

 

Item 1. Legal Proceedings

 

See Part I, Item 1, Note 10 to our unaudited condensed consolidated financial statements entitled “Commitments and Contingencies,” which is incorporated in this item by reference.

 

Item 1A. Risk Factors

 

Our business faces many risks. Any of the risks discussed in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

 

For a discussion of our potential risks and uncertainties, see the information in MPCI’s prospectus dated April 19, 2012 and filed with the SEC pursuant to Rule 424(b) on April 20, 2012. Except for the risk factor set forth below, there have been no material changes in our risk factors from those described in our prospectus filed pursuant to Rule 424(b) on April 20, 2012.

 

Recently approved final rules regulating air emissions from natural gas production operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

 

On April 17, 2012, the U.S. Environmental Protection Agency (“EPA”) approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities.  The final regulations require, among other things, the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015.  For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions.  These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment.  Compliance with these requirements could increase our costs of development and production, which costs may be significant.

 

In addition, federal agencies have recently announced two other regulatory initiatives regarding certain aspects of hydraulic fracturing that could further increase our costs to operate and decrease our levels of production.  On May 4, 2012, the U.S. Department of the Interior announced proposed rules that if adopted, would require disclosure of chemicals used in hydraulic fracturing activities upon federal and Indian lands and also would strengthen standards for well-bore integrity and the management of fluids that return to the surface during and after fracturing operations on federal and Indian lands.  Also on May 4, 2012, the EPA issued draft guidance for federal Safe Drinking Water Act permits issued to oil and natural gas exploration and production operators using diesel during hydraulic fracturing.  The adoption or implementation of these regulatory initiatives could cause us to incur increased expenditures and decrease our levels of production.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

 

On April 25, 2012, we completed our initial public offering of our common stock pursuant to our registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Goldman, Sachs & Co., Morgan Stanley & Co. LLC and Wells Fargo Securities, LLC acted as joint book-running managers and representatives of the underwriters in the offering. Pursuant to the registration statement, we registered the offer and sale of 27,600,000 shares of our $0.01 par value common stock, which included 6,000,000 shares of stock sold by the selling shareholders and 3,600,000 shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments. The sale of the shares in our initial public offering closed on April 25, 2012 and our initial public offering terminated upon completion of the closing.

 

24



Table of Contents

 

The proceeds of our initial public offering, based on the public offering price of $13.00 per share, were approximately $312.0 million. After subtracting underwriting discounts and commissions of $18.7 million and the net proceeds to the selling stockholders of $73.3 million, we received net proceeds of approximately $220.0 million from the registration and sale of 18,000,000 common shares (or $215.6 million net of estimated offering expenses paid directly by us).  We used approximately $67.1 million of the net proceeds received to redeem the Preferred Units, including interest and other charges, and approximately $99.0 million was used to pay down a portion of the borrowings under the Facility. The remaining $49.5 million was used to fund the execution of our growth strategy through our drilling program. No fees or expenses have been paid, directly or indirectly, to any officer, director, or 10% stockholder or other affiliate. We did not receive any of the proceeds from the sale of the 9,600,000 shares by the Selling Stockholders.  Immediately after the initial public offering and exercise of the option, First Reserve or its affiliates own approximately 41.4% of our outstanding common stock.

 

Item 3. Defaults upon Senior Securities

 

None.

 

Item 4. Mine Safety Disclosures

 

None.

 

Item 5. Other Information

 

None.

 

Item 6. Exhibits.

 

Exhibits included in this Report are listed in the Exhibit Index and incorporated herein by reference.

 

25



Table of Contents

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

 

MIDSTATES PETROLEUM COMPANY, INC.

 

 

Dated: June 1, 2012

/s/ John A. Crum

 

John A. Crum

 

Chief Executive Officer and President

 

 

Dated: June 1, 2012

/s/ Thomas L. Mitchell

 

Thomas L. Mitchell

 

Executive Vice President and Chief Financial Officer

 

 

Dated: June 1, 2012

/s/ Nelson M. Haight

 

Nelson M. Haight

 

Vice President and Controller

 

26



Table of Contents

 

EXHIBIT INDEX

 

Exhibit
Number

 

Exhibit Description

2.1

 

Master Reorganization Agreement (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference)

3.1

 

Amended and Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference)

3.2

 

Amended and Restated Bylaws (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference)

4.1

 

Specimen Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A filed on February 29, 2012, and incorporated herein by reference)

10.1

 

Stockholders’ Agreement among Midstates Petroleum Company, Inc. and certain equity owners (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference)

10.2

 

Executive Employment Agreement - John A. Crum (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 30, 2012, and incorporated herein by reference)

10.3

 

Executive Employment Agreement - Thomas L. Mitchell (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 30, 2012, and incorporated herein by reference)

10.4

 

Executive Employment Agreement - Stephen C. Pugh (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on April 30, 2012, and incorporated herein by reference)

10.5

 

Executive Employment Agreement - John P. Foley (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on April 30, 2012, and incorporated herein by reference)

10.6

 

2012 Long Term Incentive Plan (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on April 20, 2012, and incorporated herein by reference)

10.7

 

Form of Restricted Stock Agreement (Time Vesting) (filed as Exhibit 10.10 to the Company’s Registration Statement on Form S-1/A filed on January 20, 2012, and incorporated herein by reference)

10.8

 

Form of Notice of Restricted Stock Agreement (Time Vesting) (filed as Exhibit 10.11 to the Company’s Registration Statement on Form S-1/A filed on January 20, 2012 and incorporated herein by reference).

10.9

 

Form of Indemnification Agreement between Midstates Petroleum Company, Inc. and each of the directors and executive officers thereof (filed as Exhibit 10.12 to the Company’s Registration Statement on Form S-1/A filed on February 16, 2012, and incorporated herein by reference)

31.1*

 

Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

31.2*

 

Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

32.1**

 

Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

 

XBRL Instance Document

101.SCH

 

XBRL Schema Document

101.CAL

 

XBRL Calculation Linkbase Document

101.DEF

 

XBRL Definition Linkbase Document

101.LAB

 

XBRL Labels Linkbase Document

101.PRE

 

XBRL Presentation Linkbase Document

 


*

 

Filed herewith

**

 

Furnished herewith

 

 

 

27


XNYS:MPO Midstates Petroleum Co Inc Quarterly Report 10-Q Filling

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