10-Q 1 a15-7205_110q.htm 10-Q

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 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, 2015

 

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.)

 

321 South Boston, Suite 1000

 

 

Tulsa, Oklahoma

 

74103

(Address of principal executive offices)

 

(Zip Code)

 

(918) 947-8550

(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 x No o

 

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

 

Large accelerated filer o

 

Accelerated filer x

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

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 4, 2015 is shown below:

 

Class

 

Number of shares outstanding

Common stock, $0.01 par value

 

71,719,939

 

 

 



Table of Contents

 

MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2015

 

TABLE OF CONTENTS

 

 

Page

 

 

Glossary of Oil and Natural Gas Terms

3

 

 

PART I - FINANCIAL INFORMATION

 

 

 

Item 1. Financial Statements

4

Condensed Consolidated Balance Sheets at March 31, 2015 and December 31, 2014 (unaudited)

4

Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014 (unaudited)

5

Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2015 and 2014 (unaudited)

6

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014 (unaudited)

7

 

 

Notes to Unaudited Condensed Consolidated Financial Statements

8

 

 

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

20

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

31

 

 

Item 4. Controls and Procedures

32

 

 

PART II - OTHER INFORMATION

 

 

 

Item 1. Legal Proceedings

34

 

 

Item 1A. Risk Factors

34

 

 

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

37

 

 

Item 3. Defaults upon Senior Securities

37

 

 

Item 4. Mine Safety Disclosures

37

 

 

Item 5. Other Information

37

 

 

Item 6. Exhibits

37

 

 

SIGNATURES

38

 

 

EXHIBIT INDEX

39

 

2



Table of Contents

 

GLOSSARY OF OIL AND NATURAL GAS TERMS

 

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

 

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

 

Boe/day:  Barrels of oil equivalent per day.

 

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

 

Dry hole:  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production do not exceed production expenses and taxes.

 

Exploratory well:  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir.

 

Mcf: One thousand cubic feet of natural gas.

 

MMBoe:  One million barrels of oil equivalent.

 

MMBtu:  One million British thermal units.

 

Net acres:  The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

 

NYMEX:  The New York Mercantile Exchange.

 

Proved reserves:  Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

Reasonable certainty:  A high degree of confidence.

 

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

 

Reserves:  Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development projects to known accumulations.

 

Reservoir:  A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

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

 

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

 

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

 

3



Table of Contents

 

PART I - FINANCIAL INFORMATION

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

 

 

 

March 31, 2015

 

December 31, 2014

 

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

11,941

 

$

11,557

 

Accounts receivable:

 

 

 

 

 

Oil and gas sales

 

56,843

 

69,161

 

Joint interest billing

 

28,550

 

42,407

 

Other

 

20,157

 

22,193

 

Commodity derivative contracts

 

95,473

 

126,709

 

Other current assets

 

2,119

 

1,098

 

Total current assets

 

215,083

 

273,125

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT:

 

 

 

 

 

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

 

3,532,976

 

3,442,681

 

Other property and equipment

 

13,845

 

13,454

 

Less accumulated depreciation, depletion, amortization and impairment

 

(1,566,043

)

(1,333,019

)

Net property and equipment

 

1,980,778

 

2,123,116

 

 

 

 

 

 

 

OTHER ASSETS:

 

 

 

 

 

Deferred income taxes

 

33,119

 

35,821

 

Other noncurrent assets

 

42,619

 

43,731

 

Total other assets

 

75,738

 

79,552

 

 

 

 

 

 

 

TOTAL

 

$

2,271,599

 

$

2,475,793

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable

 

$

24,006

 

$

22,783

 

Accrued liabilities

 

182,488

 

183,831

 

Deferred income taxes

 

33,119

 

44,862

 

Total current liabilities

 

239,613

 

251,476

 

 

 

 

 

 

 

LONG-TERM LIABILITIES:

 

 

 

 

 

Asset retirement obligations

 

22,044

 

21,599

 

Long-term debt

 

1,735,150

 

1,735,150

 

Other long-term liabilities

 

1,486

 

1,706

 

Total long-term liabilities

 

1,758,680

 

1,758,455

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (Note 15)

 

 

 

 

 

 

 

 

 

 

 

STOCKHOLDERS’ EQUITY:

 

 

 

 

 

Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding

 

 

 

Series A mandatorily convertible preferred stock, $0.01 par value, $395,412 and $387,808 liquidation value at March 31, 2015 and December 31, 2014, respectively; 8% cumulative dividends; 325,000 shares issued and outstanding

 

3

 

3

 

Common stock, $0.01 par value, 300,000,000 shares authorized; 72,440,407 shares issued and 71,650,849 shares outstanding at March 31, 2015 and 70,491,732 shares issued and 69,957,055 shares outstanding at December 31, 2014

 

724

 

704

 

Treasury stock, at cost

 

(2,897

)

(2,592

)

Additional paid-in-capital

 

883,177

 

881,894

 

Retained deficit

 

(607,701

)

(414,147

)

Total stockholders’ equity

 

273,306

 

465,862

 

 

 

 

 

 

 

TOTAL

 

$

2,271,599

 

$

2,475,793

 

 

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

 

4



Table of Contents

 

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

 

 

 

For the Three Months
Ended March 31,

 

 

 

2015

 

2014

 

REVENUES:

 

 

 

 

 

Oil sales

 

$

59,257

 

$

116,222

 

Natural gas liquid sales

 

11,010

 

25,519

 

Natural gas sales

 

19,172

 

25,385

 

Gains (losses) on commodity derivative contracts - net

 

21,372

 

(22,673

)

Other

 

387

 

209

 

 

 

 

 

 

 

Total revenues

 

111,198

 

144,662

 

 

 

 

 

 

 

EXPENSES:

 

 

 

 

 

Lease operating and workover

 

23,262

 

20,127

 

Gathering and transportation

 

3,438

 

2,855

 

Severance and other taxes

 

3,565

 

7,647

 

Asset retirement accretion

 

445

 

497

 

Depreciation, depletion, and amortization

 

58,428

 

66,901

 

Impairment in carrying value of oil and gas properties

 

174,667

 

86,471

 

General and administrative

 

11,654

 

11,684

 

Acquisition and transaction costs

 

 

128

 

Advisory fees

 

1,743

 

 

Other

 

97

 

330

 

 

 

 

 

 

 

Total expenses

 

277,299

 

196,640

 

 

 

 

 

 

 

OPERATING INCOME (LOSS)

 

(166,101

)

(51,978

)

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

Interest income

 

9

 

10

 

Interest expense — net of amounts capitalized

 

(36,503

)

(33,947

)

 

 

 

 

 

 

Total other income (expense)

 

(36,494

)

(33,937

)

 

 

 

 

 

 

LOSS BEFORE TAXES

 

(202,595

)

(85,915

)

 

 

 

 

 

 

Income tax benefit

 

9,041

 

2,270

 

 

 

 

 

 

 

NET LOSS

 

$

(193,554

)

$

(83,645

)

 

 

 

 

 

 

Preferred stock dividend

 

(131

)

(2,620

)

Participating securities - Series A Preferred Stock

 

 

 

Participating securities - Non-vested Restricted Stock

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS

 

$

(193,685

)

$

(86,265

)

 

 

 

 

 

 

Basic and diluted net loss per share attributable to common shareholders

 

$

(2.88

)

$

(1.31

)

Basic and diluted weighted average number of common shares outstanding

 

67,261

 

65,987

 

 

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

 

5



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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

 

 

 

Series A
Preferred
Stock

 

Common
Stock

 

Treasury
Stock

 

Additional
Paid-in-
Capital

 

Retained
Deficit

 

Total
Stockholders’
Equity

 

Balance as of December 31, 2014

 

$

3

 

$

704

 

$

(2,592

)

$

881,894

 

$

(414,147

)

$

465,862

 

Share-based compensation

 

 

20

 

 

1,283

 

 

1,303

 

Acquisition of treasury stock

 

 

 

(305

)

 

 

(305

)

Net loss

 

 

 

 

 

(193,554

)

(193,554

)

Balance as of March 31, 2015

 

$

3

 

$

724

 

$

(2,897

)

$

883,177

 

$

(607,701

)

$

273,306

 

 

 

 

Series A
Preferred
Stock

 

Common
Stock

 

Treasury
Stock

 

Additional
Paid-in-
Capital

 

Retained
Deficit

 

Total
Stockholders’
Equity

 

Balance as of December 31, 2013

 

$

3

 

$

689

 

$

(664

)

$

871,047

 

$

(531,076

)

$

339,999

 

Share-based compensation

 

 

16

 

 

2,049

 

 

2,065

 

Acquisition of treasury stock

 

 

 

(649

)

 

 

(649

)

Net loss

 

 

 

 

 

(83,645

)

(83,645

)

Balance as of March 31, 2014

 

$

3

 

$

705

 

$

(1,313

)

$

873,096

 

$

(614,721

)

$

257,770

 

 

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

 

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

 

 

 

Three Months Ended
March 31,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net loss

 

$

(193,554

)

$

(83,645

)

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

 

 

 

 

 

(Gains) losses on commodity derivative contracts — net

 

(21,372

)

22,673

 

Net cash received (paid) for commodity derivative contracts

 

52,608

 

(14,810

)

Asset retirement accretion

 

445

 

497

 

Depreciation, depletion, and amortization

 

58,428

 

66,901

 

Impairment in carrying value of oil and gas properties

 

174,667

 

86,471

 

Share-based compensation, net of amounts capitalized to oil and gas properties

 

801

 

1,541

 

Deferred income taxes

 

(9,041

)

(2,270

)

Amortization of deferred financing costs

 

1,869

 

2,386

 

Change in operating assets and liabilities:

 

 

 

 

 

Accounts receivable — oil and gas sales

 

27,572

 

(2,767

)

Accounts receivable — JIB and other

 

13,475

 

(8,116

)

Other current and noncurrent assets

 

(1,089

)

(3,972

)

Accounts payable

 

322

 

2,813

 

Accrued liabilities

 

8,106

 

37,170

 

Other

 

(220

)

537

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

113,017

 

$

105,409

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Investment in property and equipment

 

(111,167

)

(122,780

)

 

 

 

 

 

 

Net cash used in investing activities

 

$

(111,167

)

$

(122,780

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Deferred financing costs

 

(1,161

)

(495

)

Acquisition of treasury stock

 

(305

)

(649

)

 

 

 

 

 

 

Net cash used in financing activities

 

$

(1,466

)

$

(1,144

)

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

384

 

(18,515

)

 

 

 

 

 

 

Cash and cash equivalents, beginning of period

 

$

11,557

 

$

33,163

 

 

 

 

 

 

 

Cash and cash equivalents, end of period

 

$

11,941

 

$

14,648

 

 

 

 

 

 

 

SUPPLEMENTAL INFORMATION:

 

 

 

 

 

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

 

$

71,900

 

$

134,000

 

Cash paid for interest, net of capitalized interest of $1.0 million and $4.6 million, respectively

 

2,321

 

 

 

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

 

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Table of Contents

 

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

 

1. Organization and Business

 

Midstates Petroleum Company, Inc., through its wholly owned subsidiary Midstates Petroleum Company LLC, engages in the business of drilling for, and production of, oil, natural gas liquids (“NGLs”) and natural gas. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”), which was previously a wholly owned subsidiary of Midstates Petroleum Holdings LLC (“Holdings LLC”).  The terms “Company,” “we,” “us,” “our,” and similar terms when used in the present tense, prospectively or for historical periods since April 25, 2012, refer to Midstates Petroleum Company, Inc. and its subsidiary, unless the context indicates otherwise.

 

The Company has oil and gas operations and properties in Oklahoma, Texas and Louisiana. At March 31, 2015, the Company operated oil and natural gas properties as one reportable segment engaged in the exploration, development and production of oil, natural gas liquids and natural gas. The Company’s management evaluates performance based on one reportable segment as all our operations are located in the United States and therefore we maintain one cost center.

 

2. Liquidity and Capital Resources

 

As of March 31, 2015, the Company had available cash of approximately $11.9 million and availability under its reserve based revolving credit facility (the “Credit Facility”) of approximately $88.4 million. As of March 31, 2015, payments due on contractual obligations during the remainder of 2015, as well as for the years ending December 31, 2016 and 2017 are approximately $143.5 million, $132.0 million and $131.2 million, respectively. This includes approximately $387.8 million of interest payments on the senior notes, but excludes interest on our Credit Facility, for the remainder of 2015, as well as for the years ending December 31, 2016 and 2017.  The Company believes it will need to complete certain transactions, including management of debt capital structure and potential asset sales, to have sufficient liquidity to satisfy these obligations, as well as other obligations such as fixed drilling commitments and operating leases, in the long term.

 

Liquidity Sufficiency

 

As a result of substantial declines in oil and gas prices during the latter half of 2014 and continuing into the first part of 2015, the liquidity outlook of the Company has been impacted.  As a result, we expect lower operating cash flows than previously experienced and if commodity prices continue to remain low, our liquidity will be further impacted as current hedging contracts expire.  During the three months ended March 31, 2015, the Company received cash payments on settled derivative contracts of $52.6 million.  Such cash payments will not be received in 2016 and future periods due to the expiration of our hedging contracts.

 

As a result of the commodity price decline and the Company’s substantial debt burden, the Company continues to believe forecasted cash and expected available credit capacity will not be sufficient to meet commitments as they come due and, absent a material improvement in oil and gas prices, the Company will not be able to remain in compliance with current debt covenants unless able to successfully increase liquidity. Additionally, while the terms of the Credit Facility were amended in March 2015 to allow the divestiture of certain of its oil and gas properties in Beauregard and Calcasieu Parishes, Louisiana, which closed on April 21, 2015 (“Sale of Dequincy”), with no associated reduction in the borrowing base of the Credit Facility, absent additional amendments, the terms of the Credit Facility and the indentures governing the senior notes require that some or all of the proceeds from certain future asset sales be used to permanently reduce outstanding debt, which could substantially reduce the amount of proceeds retained.  Additionally, the covenants in these debt instruments impose limitations on the amount and type of additional indebtedness the Company can incur, which may significantly reduce the ability to obtain liquidity through the incurrence of additional indebtedness. Furthermore, the ability to refinance any of the existing indebtedness on commercially reasonable terms may be materially and adversely impacted by the current conditions in the energy industry and the Company’s financial condition.

 

The interest payment obligations are substantial, and the Company is required to pay approximately $32 million in interest on the 2020 Senior Notes (as defined below) on each of April 1 and October 1 and approximately $32 million in interest on the 2021 Senior Notes (as defined below) on each of June 1 and December 1. The Company received a going concern qualification from its independent registered public accounting firm for the year ended December 31, 2014, but obtained a waiver to the Credit Facility waiving any default as a result of receiving such qualification. As the Company pursues the actions mentioned above to increase liquidity, it will likely need to negotiate additional waivers or amendments to the Credit Facility or indentures to facilitate those actions. There can be no assurance that the lenders or the holders of the senior notes will agree to any amendment or waiver on acceptable terms and if a default occurs, a failure to do so may provide the lenders the opportunity to accelerate the outstanding debt under these facilities and it would be classified as a current liability on the balance sheet.

 

The uncertainty associated with the Company’s ability to meet commitments as they come due or to repay outstanding debt raises substantial doubt about the Company’s ability to continue as a going concern. The accompanying financial statements do not include

 

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any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with the ability to meet obligations as they come due.

 

The Company continues to pursue a number of actions including (i) actively managing the debt capital structure, (ii) selling additional assets, (iii) minimizing capital expenditures, (iv) obtaining waivers or amendments from lenders, (v) effectively managing working capital and (vi) improving cash flows from operations. As previously announced, in early 2015 the Company engaged Evercore and Kirkland & Ellis to assist with reviewing all options to improve its liquidity profile and strengthen its balance sheet. These efforts continue in earnest and the Company is considering all available strategic alternatives and financing possibilities, including, without limitation, the incurrence of additional secured indebtedness and the exchange or refinancing of existing obligations.  We can provide no assurance that these discussions will result in the completion of a transaction, or that any completed transaction will result in sufficient liquidity to satisfy our obligations.

 

Financial Ratio Covenants

 

As of March 31, 2015, the ratio of net consolidated indebtedness to EBITDA was 3.7:1.0 and the ratio of current assets to current liabilities was 1.0:1.0. As calculated for covenant compliance purposes, the Company’s current assets exceeded its current liabilities by approximately $1.5 million at March 31, 2015. If liquidity concerns are not addressed in the near term, the Company will likely breach the financial ratio covenants of the Credit Facility in 2015. As of March 31, 2015, the Company was in compliance with the financial ratio covenants included in the Credit Facility.

 

Borrowing Base Redetermination

 

On March 24, 2015, the Company and Midstates Sub entered into a Sixth Amendment (the “Sixth Amendment”) to the Second Amended and Restated Credit Agreement dated as of June 8, 2012, among Midstates, Midstates Sub, as borrower, SunTrust Bank, N.A., as administrative agent, and the lenders and other parties thereto (the “Credit Agreement”). The Sixth Amendment provides that Midstates Sub’s borrowing base will remain at its current size of $525.0 million as part of the regular semi-annual borrowing base redetermination under the Credit Agreement. The Sixth Amendment also confirmed that the borrowing base will not be reduced as a result of the Sale of Dequincy. The Sixth Amendment amends the required ratio of net consolidated indebtedness to EBITDA under the Credit Agreement for each of the fiscal quarters in 2015 from 4.0:1.0 to 4.5:1.0.  Additionally, the Sixth Amendment amends the mortgage requirements under the Credit Agreement to provide for an increase from 80% to 90% for the percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders.

 

Cross Default Provisions

 

The Company’s debt facilities contain significant cross default and/or cross acceleration provisions where a default under the Credit Facility or one of the indentures could enable the lenders of the other debt to also declare events of default and accelerate repayment of the obligations under those debt instruments. In general, these cross default/cross acceleration provisions are as follows:

 

·                  The Credit Facility allows the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is the result of the failure to make any payment when due in respect of other indebtedness having an aggregate principal amount of at least 5% of the then effective borrowing base and such failure continues after the applicable grace or notice period; or (ii) is the result of a failure to perform any condition, covenant or other event and such failure permits the holders of such other indebtedness to cause the acceleration of such other indebtedness.

 

·                  The indentures governing the senior notes allow the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is caused by a failure to make any payment of principal prior to the expiration of the grace period following the final maturity date of such indebtedness; or (ii) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of any such indebtedness, together with the principal amount of any other indebtedness with respect to which an event described herein has occurred, aggregates $50.0 million or more.

 

3. 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 in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2014 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 16, 2015.

 

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All intercompany transactions have been eliminated in consolidation. 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.

 

Recently Issued Standards Not Yet Adopted

 

In April 2015, the FASB issued Accounting Standards Update 2015-03 “Interest-Imputation of Interest (Subtopic 835-30):  Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”).  ASU 2015-03 requires that debt issuance costs related to a recognized liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.  The recognition and measurement guidance for debt issuance costs is not affected by ASU 2015-03.  ASU 2015-03 is effective retrospectively for the Company beginning on January 1, 2016.  The Company does not expect the reclassification of debt issuance costs on the Company’s consolidated balance sheet as a result of the adoption of ASU 2015-03 to have a material impact on its consolidated financial statements or related disclosures.

 

Correction of Operating and Investing Cash Flows for the Three Months Ended March 31, 2014

 

In the first quarter of 2015, the Company determined that it had incorrectly presented non-cash accrued capital expenditures in its Statements of Cash Flows since December 31, 2012. Management concluded the misstatement is immaterial to previously issued financial statements; however, the Company has corrected the cash flow presentation in the accompanying Condensed Consolidated Statement of Cash Flows for the three months ended March 31, 2014. There was no impact of the misstatement on the Condensed Consolidated Balance Sheet as of December 31, 2014, or on the Condensed Consolidated Statement of Operations for the three months ended March 31, 2014. The impact of the correction is shown in the table below (in thousands):

 

 

 

For the Three Months
Ended March 31, 2014

 

Statement of Cash Flows

 

As
Previously
Reported

 

As Restated

 

 

 

 

 

 

 

Change in operating assets and liabilities:

 

 

 

 

 

accounts receivable - JIB and other

 

$

(16,093

)

$

(8,116

)

Net cash provided by operating activities

 

97,432

 

105,409

 

 

 

 

 

 

 

Investment in property and equipment

 

(114,803

)

(122,780

)

Net cash used in investing activities

 

(114,803

)

(122,780

)

 

4. Fair Value Measurements of Financial Instruments

 

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, 2015 and December 31, 2014, all of the Company’s commodity derivative contracts were with seven bank counterparties and were classified as Level 2 in the fair value input hierarchy.

 

Derivative instruments listed below are presented gross and include swaps that are carried at fair value. The Company records the net change in the fair value of these positions in “Gains (losses) on commodity derivative contracts — net” in the Company’s unaudited condensed consolidated statements of operations.

 

 

 

Fair Value Measurements at March 31, 2015

 

 

 

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

 

$

 

$

79,344

 

$

 

$

79,344

 

Commodity derivative gas swaps

 

 

16,129

 

 

16,129

 

Total assets

 

$

 

$

95,473

 

$

 

$

95,473

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

 

$

 

$

 

Commodity derivative gas swaps

 

 

 

 

 

Total liabilities

 

$

 

$

 

$

 

$

 

 

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Fair Value Measurements at December 31, 2014

 

 

 

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

 

$

 

$

106,450

 

$

 

$

106,450

 

Commodity derivative gas swaps

 

 

20,259

 

 

20,259

 

Total assets

 

$

 

$

126,709

 

$

 

$

126,709

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

 

$

 

$

 

Commodity derivative gas swaps

 

 

 

 

 

Total liabilities

 

$

 

$

 

$

 

$

 

 

5. Risk Management and Derivative Instruments

 

The Company’s production is exposed to fluctuations in crude oil, NGLs and natural gas prices. The Company periodically utilizes derivative financial instruments to provide partial protection against declines in oil, natural gas and NGLs prices by reducing the risk of price volatility and the effect such volatility could have on the Company’s operations and its ability to finance its capital budget and operations. The Company’s decision on the quantity and price at which it chooses to hedge its production is based on its view of existing and forecasted oil, natural gas and NGLs production volumes, planned drilling projects and current and future market conditions. The Company currently utilizes swaps to manage fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The oil, NGLs and gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that management believes have a high degree of historical correlation with actual prices received by the Company for its oil, NGLs and natural gas production.

 

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market 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. Due to the netting arrangements, had the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at March 31, 2015 would have been approximately $95.5 million.

 

Commodity Derivative Contracts

 

As of March 31, 2015, the Company had the following open commodity derivative contract positions:

 

 

 

Hedged
Volume

 

Weighted-Average
Fixed Price

 

Oil (Bbls):

 

 

 

 

 

WTI Swaps — 2015

 

2,196,000

 

$

88.04

 

 

 

 

 

 

 

Natural Gas (MMBtu):

 

 

 

 

 

Swaps — 2015 (1)

 

13,750,000

 

$

4.13

 

 


(1)         Includes 1,500,000 MMBtus in natural gas swaps that priced during the period, but had not cash settled as of March 31, 2015.

 

Balance Sheet Presentation

 

The following table summarizes the gross fair values 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 unaudited condensed consolidated balance sheets at March 31, 2015 and December 31, 2014, respectively (in thousands):

 

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Type

 

Balance Sheet Location (1)

 

March 31, 2015

 

December 31, 2014

 

Oil Swaps

 

Derivative financial instruments — Current Assets

 

$

79,344

 

$

106,450

 

Gas Swaps

 

Derivative financial instruments — Current Assets

 

16,129

 

20,259

 

Total derivative fair value at period end

 

 

 

$

95,473

 

$

126,709

 

 


(1)         The fair values of commodity derivative instruments reported in the Company’s consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets at March 31, 2015 and December 31, 2014, respectively (in thousands):

 

 

 

 

 

March 31, 2015

 

Not Designated as
ASC 815 Hedges:

 

Balance Sheet Classification

 

Gross
Recognized
Assets/
Liabilities

 

Gross
Amounts
Offset

 

Net Recognized
Fair Value Assets/
Liabilities

 

Derivative assets:

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Derivative financial instruments - current

 

$

95,473

 

$

 

$

95,473

 

Commodity contracts

 

Derivative financial instruments - noncurrent

 

 

 

 

 

 

 

 

$

95,473

 

$

 

$

95,473

 

Derivative liabilities:

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Derivative financial instruments - current

 

$

 

$

 

$

 

Commodity contracts

 

Derivative financial instruments - noncurrent

 

 

 

 

 

 

 

 

$

 

$

 

$

 

 

 

 

 

 

December 31, 2014

 

Not Designated as
ASC 815 Hedges:

 

Balance Sheet Classification

 

Gross
Recognized
Assets/
Liabilities

 

Gross
Amounts
Offset

 

Net Recognized
Fair Value Assets/
Liabilities

 

Derivative assets:

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Derivative financial instruments - current

 

$

126,709

 

$

 

$

126,709

 

Commodity contracts

 

Derivative financial instruments - noncurrent

 

 

 

 

 

 

 

 

$

126,709

 

$

 

$

126,709

 

Derivative liabilities:

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Derivative financial instruments - current

 

$

 

$

 

$

 

Commodity contracts

 

Derivative financial instruments - noncurrent

 

 

 

 

 

 

 

 

$

 

$

 

$

 

 

Gains (losses) on Commodity Derivative Contracts

 

The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, commodity derivative contracts are marked-to-market each quarter with the change in fair value during the periodic reporting period recognized currently as a gain or loss in “Gains (losses) on commodity derivative contracts - net” within revenues in the unaudited condensed consolidated statements of operations.

 

The following table presents “Gains (losses) on commodity derivative contracts — net” for the periods presented:

 

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For the Three Months
Ended March 31,

 

 

 

2015

 

2014

 

 

 

(in thousands)

 

Net cash received (paid) for commodity derivative contracts

 

$

52,608

 

$

(14,810

)

Unrealized net losses

 

(31,236

)

(7,863

)

Gains (losses) on commodity derivative contracts - net

 

$

21,372

 

$

(22,673

)

 

Cash settlements, as presented in the table above, represent realized gains or losses related to the Company’s derivative instruments. In addition to cash settlements, the Company also recognizes fair value changes on its derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

 

6. Property and Equipment

 

 

 

March 31, 2015

 

December 31, 2014

 

 

 

(in thousands)

 

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

 

 

 

 

 

Proved properties

 

$

3,491,783

 

$

3,398,146

 

Unevaluated properties

 

41,193

 

44,535

 

Other property and equipment

 

13,845

 

13,454

 

Less accumulated depreciation, depletion, amortization and impairment

 

(1,566,043

)

(1,333,019

)

Net property and equipment

 

$

1,980,778

 

$

2,123,116

 

 

Oil and Gas Properties

 

The Company capitalizes internal costs directly related to exploration and development activities to oil and gas properties. During the three months ended March 31, 2015 and 2014, the Company capitalized the following amounts (in thousands):

 

 

 

Three Months Ended March 31,

 

 

 

2015

 

2014

 

Internal costs capitalized to oil and gas properties (1)

 

$

2,302

 

$

3,124

 

 


(1)         Inclusive of $0.5 million of qualifying share-based compensation expense for the three months ended March 31, 2015 and 2014.

 

The Company accounts for its oil and gas properties under the full cost method. Under the full cost method, proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income.

 

The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations.

 

At March 31, 2015 and 2014, capitalized costs exceeded the ceiling and the Company recorded an impairment of oil and gas properties of $174.7 million and $86.5 million, respectively.  The impairment at March 31, 2015 was primarily due to continued low commodity prices, which resulted in a reduction of the discounted present value of the Company’s proved oil and natural gas reserves.

 

Depreciation, depletion and amortization is calculated using the units-of-production method based upon estimates of proved reserve quantities, the Company’s costs incurred for proved developed properties and costs expected to be incurred to develop its proved

 

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undeveloped reserves.   The following table presents depletion expense related to oil and gas properties for the three months ended March 31, 2015 and 2014, respectively:

 

 

 

Three Months Ended March 31,

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

(per Boe)

 

Depletion expense

 

$

57,605

 

$

66,204

 

$

18.73

 

$

25.37

 

Depreciation on other property

 

823

 

697

 

0.27

 

0.26

 

Depreciation, depletion, and amortization

 

$

58,428

 

$

66,901

 

$

19.00

 

$

25.63

 

 

Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least quarterly to determine if impairment has occurred. Unevaluated property was $41.2 million and $44.5 million at March 31, 2015 and December 31, 2014, respectively.

 

Sale of Dequincy Assets

 

On April 21, 2015, the Company closed on the sale of its ownership interest in developed and undeveloped acreage in the Dequincy area located in Beauregard and Calcasieu Parishes, Louisiana for $44 million to Pintail Oil and Gas LLC. The net proceeds of approximately $42 million, which was net of customary closing adjustments, will be reflected as a reduction of oil and natural gas properties, with no gain or loss recognized. The proceeds from the sale will be used to pay down a portion of the outstanding borrowings under the Company’s revolving credit facility and for general corporate purposes.

 

7. Other Noncurrent Assets

 

At March 31, 2015 and December 31, 2014 other noncurrent assets consisted of the following:

 

 

 

March 31, 2015

 

December 31, 2014

 

 

 

(in thousands)

 

Deferred financing costs

 

$

37,099

 

$

37,807

 

Field equipment inventory

 

5,309

 

5,713

 

Other

 

211

 

211

 

Other noncurrent assets

 

$

42,619

 

$

43,731

 

 

8. Accrued Liabilities

 

At March 31, 2015 and December 31, 2014 accrued liabilities consisted of the following:

 

 

 

March 31, 2015

 

December 31, 2014

 

 

 

(in thousands)

 

Accrued oil and gas capital expenditures

 

$

52,709

 

$

76,398

 

Accrued revenue and royalty distributions

 

46,286

 

51,292

 

Accrued lease operating and workover expense

 

16,313

 

10,113

 

Accrued interest

 

53,833

 

21,521

 

Accrued taxes

 

4,618

 

4,226

 

Other

 

8,729

 

20,281

 

Accrued liabilities

 

$

182,488

 

$

183,831

 

 

9. Asset Retirement Obligations

 

Asset Retirement Obligations (“AROs”) represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the ARO at inception is capitalized as part of the carrying amount of the related long-lived assets. AROs approximated $22.0 million and $21.6 million as of March 31, 2015 and December 31, 2014, respectively, and the liability has been accreted to its present value as of March 31, 2015 and December 31, 2014.

 

10. Long-Term Debt

 

The Company’s long-term debt as of March 31, 2015 and December 31, 2014 is as follows:

 

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At March 31, 2015

 

At December 31, 2014

 

 

 

(in thousands)

 

Revolving credit facility, due 2018

 

$

435,150

 

$

435,150

 

Senior notes, due 2020

 

600,000

 

600,000

 

Senior notes, due 2021

 

700,000

 

700,000

 

Long-term debt

 

$

1,735,150

 

$

1,735,150

 

 

Reserve-based Credit Facility

 

As of March 31, 2015, the Company’s credit facility consisted of a $750 million Credit Facility with a borrowing base supported by the Company’s Mississippian Lime and Anadarko Basin oil and gas assets. The borrowing base was reaffirmed on March 24, 2015 at $525 million, with no reduction upon the closing in April of the Sale of Dequincy. At March 31, 2015, the Company had drawn $435.2 million on the Credit Facility and had outstanding letters of credit obligations totaling $1.4 million.

 

The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of the Company’s oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon the Company’s borrowing base utilization, between 2.00% and 3.00% per annum. At March 31, 2015 and 2014, the weighted average interest rate was 3.0% and 2.7%, respectively.

 

In addition to interest expense, the Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.50% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

 

The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October 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 Credit 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. 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.

 

The Credit Facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of net debt to EBITDA (i.e. leverage ratio) and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. Pursuant to the Sixth Amendment, the Company is required to maintain a leverage ratio of not more than 4.5 to 1.0 through December 31, 2015 and 4.0 to 1.0 for each quarter thereafter. The Credit Facility also limits the Company’s ability to make any dividends, distributions or redemptions.

 

As of March 31, 2015, the Company was in compliance with the current ratio and the ratio of net consolidated indebtedness to EBITDA covenants as set forth in the Credit Facility. The Company’s current ratio at March 31, 2015 was 1.0 to 1.0. As calculated for covenant compliance purposes, the Company’s current assets exceeded its current liabilities by approximately $1.5 million at March 31, 2015. At March 31, 2015, the Company’s leverage ratio was 3.7 to 1.0.

 

Based upon the recent amendments to the Credit Facility, the Company believes its carrying amount at March 31, 2015 approximates its fair value (Level 2) due to the variable nature of the applicable interest rate and current secured financing terms available to the Company.

 

2020 Senior Notes

 

On October 1, 2012, the Company issued $600 million in aggregate principal amount of 10.75% senior notes due in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). In October 2013, these notes were exchanged for an equal principal amount of notes with identical terms other than registration under the Securities Act and the omission of restrictions on transfer, registration rights and provisions for additional interest (the “2020 Senior Notes”). The 2020 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The Company does not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The 2020 Senior Notes Indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

 

The 2020 Senior Notes Indenture contains covenants that, among other things, restrict the Company’s ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens;

 

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(v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company’s affiliates; (vii) consolidate, merge or sell substantially all of the Company’s assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business the Company conducts and (x) enter into agreements restricting the ability of the Company’s current and any future subsidiaries to pay dividends.

 

The estimated fair value of the 2020 Senior Notes was $302.3 million as of March 31, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2020 Senior Notes was approximately 11.1% for the three months ended March 31, 2015 and 2014.

 

2021 Senior Notes

 

On May 31, 2013, the Company issued $700 million in aggregate principal amount of 9.25% senior notes due 2021. In October 2013, these notes were exchanged for an equal principal amount of notes with identical terms other than registration under the Securities Act and the omission of restrictions on transfer, registration rights and provisions for additional interest (the “2021 Senior Notes”).

 

The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes.

 

The 2021 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The 2021 Senior Notes indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

 

The terms of the covenants in the 2021 Senior Notes Indenture are substantially identical to those of the 2020 Senior Notes discussed above.

 

The estimated fair value of the 2021 Senior Notes was $339.5 million as of March 31, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2021 Senior Notes was approximately 9.6% for the three months ended March 31, 2015 and 2014.

 

11. Preferred Stock

 

Series A Preferred Stock

 

In connection with the Company’s acquisition of its Mississippian Lime properties, on September 28, 2012, the Company designated 325,000 shares of Series A Mandatorily Convertible Preferred Stock (the “Series A Preferred Stock”) with an initial liquidation preference of $1,000 per share and an 8% per annum dividend, payable semiannually at the Company’s option in cash or through an increase in the liquidation preference.  The Series A Preferred Shares are convertible after October 1, 2013, in whole but not in part and at the option of the holders of a majority of the outstanding shares of Series A Preferred Stock, into a number of shares of the Company’s common stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share and, if not previously converted, are mandatorily convertible at September 30, 2015 into shares of the Company’s common stock at a conversion price no greater than $13.50 per share and no less than $11.00 per share, with the ultimate conversion price dependent upon the volume weighted average price of the Company’s common stock during the 15 trading days immediately prior to September 30, 2015.  The Series A Preferred Stock was issued on October 1, 2012.

 

On March 30, 2015, the Company elected to pay the $13 million semi-annual dividend due on that date through an increase in the Series A Preferred Stock liquidation preference to $1,217. As a result, the Company will be obligated to issue between 5,215,718 and 6,401,108 additional shares of common stock upon conversion of the Series A Preferred stock, with the ultimate number of shares dependent upon the conversion price then in effect as described above.

 

The following table demonstrates the number of shares to be issued upon conversion through March 31, 2015 at the respective conversion rates based upon the current liquidation preference:

 

 

 

Conversion at
$13.50/share

 

Conversion at
$11.00/share

 

 

 

 

 

 

 

Number of Common Shares Issuable Upon Conversion

 

29,289,792

 

35,946,563

 

 

Share Activity

 

The aggregate number of shares of Series A Preferred Stock outstanding at March 31, 2015 and December 31, 2014 was 325,000.

 

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12. Equity and Share-Based Compensation

 

Common Shares

 

Share Activity

 

The following table summarizes changes in the number of outstanding shares during the three months ended March 31, 2015:

 

 

 

Number of Shares

 

 

 

Common
Stock

 

Treasury
Stock

 

Share count as of December 31, 2014

 

70,491,732

 

(534,677

)

Grants of restricted stock

 

2,459,754

 

 

Forfeitures of restricted stock

 

(511,079

)

 

Acquisition of treasury stock

 

 

(254,881

)

Share count as of March 31, 2015

 

72,440,407

 

(789,558

)

 

The Company’s 2012 Long Term Incentive Unit Plan (discussed below) allows for the recipients of restricted stock to surrender a portion of their shares upon vesting to satisfy Federal Income Tax (“FIT”) withholding requirements. The Company then remits to the IRS the cash equivalent of the FIT withholding liability. Shares surrendered to the Company in this fashion have been treated as treasury shares acquired at a cost equivalent to the related tax liability. These shares are available for future issuance by the Company.

 

Incentive Units

 

At March 31, 2015, 1,099 incentive units were issued and outstanding. These incentive units were issued prior to the Company’s initial public offering. In connection with the corporate reorganization that occurred immediately prior to the Company’s initial public offering, these incentive units 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 FRMI incentive units has been recognized by the Company, as any payout under the FRMI incentive units is not considered probable as the amount of FRMI Profits, if any, cannot be determined.

 

Share-based Compensation

 

2012 Long Term Incentive Plan

 

The 2012 Long Term Incentive Plan (the “2012 LTIP”) provides a means for the Company to attract and retain employees, directors and consultants, and a method whereby employees, directors and consultants of the Company who contribute to its success can acquire and maintain stock ownership or awards, the value of which is tied to the performance of the Company, thereby strengthening their concern for the welfare of the Company and their desire to remain employed.

 

The 2012 LTIP provides for the granting of Options (Incentive and other), Restricted Stock Awards, Restricted Stock Units, Stock Appreciation Rights, Dividend Equivalents, Bonus Stock, Other Stock Based Awards, Annual Incentive Awards, Performance Awards, or any combination of the foregoing (the “Awards”). Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award are as determined by the Compensation Committee of the Board of Directors. As of December 31, 2014, a total of 8,638,435 common share Awards are authorized for issuance under the 2012 LTIP. Shares of stock subject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awards under the 2012 LTIP.

 

Non-vested Stock Awards

 

At March 31, 2015, the Company had 4,110,542 non-vested shares of restricted common stock outstanding pursuant to the 2012 LTIP. Shares granted under the LTIP generally vest ratably over a period of three years (one-third on each anniversary of the grant); however, beginning in 2013, shares granted under the 2012 LTIP to directors are subject to one-year cliff vesting.

 

The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period.

 

The following table summarizes the Company’s non-vested share award activity for the three months ended March 31, 2015:

 

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Shares

 

Weighted
Average
Grant Date
Fair Value

 

Non-vested shares outstanding at December 31, 2014

 

3,062,015

 

$

5.28

 

Granted

 

2,459,754

 

$

1.25

 

Vested

 

(900,148

)

$

5.22

 

Forfeited

 

(511,079

)

$

5.44

 

Non-vested shares outstanding at March 31, 2015

 

4,110,542

 

$

2.86

 

 

Unrecognized expense, adjusted for estimated forfeitures, as of March 31, 2015 for all outstanding restricted stock awards, was $8.9 million and will be recognized over a weighted average period of 1.9 years.

 

At March 31, 2015, 1,832,381 shares remain available for issuance under the terms of the 2012 LTIP.

 

The share based compensation costs (net of amounts capitalized to oil and gas properties) recognized as general and administrative expense by the Company for the three months ended March 31, 2015 and 2014 were $0.8 million and $1.5 million, respectively, all related to the 2012 LTIP.

 

13. Income Taxes

 

The Company has recorded a tax benefit on its year-to-date pre-tax loss. The Company believes this methodology to be more appropriate at this time due to uncertainty in forecasting the annual effective tax rate (or benefit) on 2015 income (or loss) due to previously recorded property impairments, the effects of federal and state valuation allowance adjustments, and hedging volatility.

 

For the three months ended March 31, 2015, the Company’s effective tax rate was approximately 4.5%. The Company’s effective tax rate for the first quarter of 2015 differs from the federal statutory rate of 35% due to the effect of recurring permanent adjustments, state income taxes and changes in the valuation allowance. During 2015, the Company recorded $70.9 million in additional valuation allowance in light of the impairment of oil and gas properties and the settlement of certain hedging contracts that existed at December 31, 2014, bringing the total valuation allowance to $74.7 million at March 31, 2015.

 

A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its deferred tax assets are realizable except to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment.

 

The Company expects to incur a tax loss in the current year due to the flexibility in deducting or capitalizing current year intangible drilling costs; thus no current income taxes are anticipated to be paid.

 

14. Net Loss Per Share

 

The Company’s Series A Preferred Stock has the nonforfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. The Company’s nonvested stock awards, which are granted as part of the 2012 LTIP, contain nonforfeitable rights to dividends and as such, are considered to be participating securities and, together with the Series A Preferred Stock, are included in the computation of basic and diluted earnings (loss) per share, pursuant to the two class method. In the calculation of basic earnings (loss) per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

 

The computation of diluted earnings per share attributable to common shareholders reflects the potential dilution that could occur if securities or other contracts to issue common shares that are dilutive were exercised or converted into common shares (or resulted in the issuance of common shares) and would then share in the earnings of the Company. During the periods in which the Company records a loss from continuing operations attributable to common shareholders, securities would not be dilutive to net loss per share and conversion into common shares is assumed to not occur. Diluted net income per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method; the more dilutive of the two calculations is presented below.

 

The following table (in thousands, except per share amounts) provides a reconciliation of net loss to preferred shareholders, common shareholders, and non-vested restricted shareholders for purposes of computing net loss per share for the three months ended March 31, 2015 and 2014, respectively:

 

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Three Months
Ended March 31,

 

 

 

2015

 

2014

 

Net loss

 

$

(193,554

)

$

(83,645

)

Preferred Dividend (1)

 

(131

)

(2,620

)

Net loss attributable to shareholders

 

$

(193,685

)

$

(86,265

)

 

 

 

 

 

 

Participating securities - Series A Preferred Stock (2)

 

 

 

Participating securities - Non-vested Restricted Stock (2)

 

 

 

Net loss attributable to common shareholders

 

$

(193,685

)

$

(86,265

)

 

 

 

 

 

 

Weighted average shares outstanding

 

67,261

 

65,987

 

Net loss per share

 

$

(2.88

)

$

(1.31

)

 


(1)         Calculation of the preferred stock dividend is discussed in Note 11.

(2)         As these shares are participating securities that participate in earnings, but are not required to participate in losses, this calculation demonstrates that there is not an allocation of the loss to the non-vested restricted stockholders.

 

The aggregate number of common shares outstanding at March 31, 2015 was 71,650,849 of which 4,110,542 were non-vested restricted shares.

 

15. Commitments and Contingencies

 

Litigation

 

The Company is involved in various matters incidental to its operations and business that might give rise to a loss contingency.  These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental authorities or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws.   Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices.

 

The Company vigorously defends itself in these matters.  If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of the loss can be reasonably estimated, it accrues a liability for the contingent obligation.  As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company’s accruals could have a material effect on its results of operations.

 

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

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto for the year ended December 31, 2014, and the related management’s discussion and analysis contained in our annual report on Form 10-K dated and filed with the Securities and Exchange Commission (“SEC”) on March 16, 2015, as well as the unaudited condensed consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

Various statements contained in or incorporated by reference into this report 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, and the plans, beliefs, expectations, intentions 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 annual report filed on Form 10-K dated and filed with the SEC on March 16, 2015, 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;

·                  estimated future net reserves and present value thereof;

·                  technology;

·                  financial condition, revenues, cash flows and expenses;

·                  levels of indebtedness, liquidity and compliance with debt covenants;

·                  financial strategy, budget, projections and operating results;

·                  oil and natural gas realized prices;

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

·                  availability of drilling and production equipment;

·                  availability of oilfield labor;

·                  availability of third party natural gas gathering and processing capacity;

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

·                  availability and terms of capital;

·                  drilling of wells, including our identified drilling locations;

·                  successful results from our identified drilling locations;

·                  marketing of oil and natural gas;

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

·                  infrastructure for salt water disposal and electricity;

·                  sources of electricity utilized in operations and the related infrastructures;

·                  costs of developing our properties and conducting other operations;

·                  general economic conditions;

·                  effectiveness of our risk management activities;

·                  environmental liabilities;

·                  counterparty credit risk;

·                  the outcome of pending and future litigation;

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

·                  developments in oil producing and natural gas producing countries;

·                  uncertainty regarding our future operating results; and

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

 

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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. The price of oil and natural gas declined significantly in late 2014 and early 2015. Any continued or extended decline in oil and natural gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. 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. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and elsewhere in this quarterly report.

 

Overview

 

We are an independent exploration and production company focused on the application of modern drilling and completion techniques to oil-prone resources in the United States. Our operations originally focused on the Upper Gulf Coast Tertiary trend onshore in Louisiana, which we refer to as our “Gulf Coast” operating area. We began operations in the Mississippian Lime trend in Oklahoma with the October 1, 2012 closing of our acquisition (“Eagle Property Acquisition”) of interests in producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and related hedging instruments from Eagle Energy Production, LLC (“Eagle Energy”). On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (the “Anadarko Basin Acquisition”), before customary post-closing adjustments. Subsequent to the closing of the Eagle Property Acquisition and the Anadarko Basin Acquisition, the Company has oil and gas operations and properties in Louisiana, Oklahoma and Texas.

 

We were incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”), a wholly-owned subsidiary of Midstates Petroleum Holdings LLC.  With the completion of our initial public offering on April 25, 2012, we became a publicly traded company. Our common stock is listed on the NYSE under the ticker symbol “MPO.” The terms “Company,” “we,” “us,” “our,” and similar terms refer to us and our subsidiary, unless the context indicates otherwise.

 

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. 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.

 

Recent Development – Sale of Dequincy Assets

 

On April 21, 2015, we closed on the sale of ownership interest in developed and undeveloped acreage in the Dequincy area located in Beauregard and Calcasieu Parishes, Louisiana for $44 million to Pintail Oil and Gas LLC. The net proceeds of approximately $42 million, which was net of customary closing adjustments, will be reflected as a reduction of oil and natural gas properties, with no gain or loss recognized. The proceeds from the sale will be used to pay down a portion of the outstanding borrowings under our revolving credit facility and for general corporate purposes.

 

Risks, Uncertainties and Going Concern

 

As of March 31, 2015, we had available cash of approximately $11.9 million and availability under our Credit Facility of approximately $88.4 million.  As discussed above, we closed on the sale of our Dequincy assets on April 21, 2015 for net proceeds of approximately $42.0 million (net of customary purchase price adjustments).  The terms of the Credit Facility were amended in March 2015 to allow the divestiture of these assets with no associated reduction in the borrowing base of the Credit Facility.

 

As a result of substantial declines in oil and gas prices during the latter half of 2014 and continuing into the first part of 2015, our liquidity outlook has been impacted.  Decreases in commodity prices directly impact our revenues and associated operating cash flows and consequently our ability to fund our capital program and service our debt.  Our interest payment obligations are substantial, and we are required to pay approximately $32 million in interest on the 2020 Senior Notes on each of April 1 and October 1 and approximately $32 million in interest on the 2021 Senior Notes on each of June 1 and December 1. Our production volumes will decline as reserves are depleted, further impacting our liquidity, unless we expend capital resources in successful development and exploration activities or acquire properties with existing production.

 

The borrowing base for our senior reserve based revolving credit facility (the “Credit Facility”) is substantially based upon the value of our proved reserves and our commodity hedging instruments as determined by the lenders based on their commodity price deck. Despite a significant downward revision of the value of our proved reserves, our borrowing base for our credit facility was reaffirmed on March 24, 2015 at $525 million without reduction. Our borrowing base for our Credit Facility could be reduced at our October 1 borrowing base redetermination date due to downward revisions in our lenders’ commodity price deck, which would reduce the value of our proved reserves calculated thereunder, and the expiration of our commodity hedging instruments. If such a reduction occurs, we could be required to repay any borrowings in excess of the redetermined borrowing base and our available liquidity would be reduced.

 

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The uncertainty associated with our ability to meet our commitments as they come due or to repay our outstanding debt raises substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with our ability to meet our obligations as they come due.

 

As a result of the events and circumstances described above, we believe that our forecasted cash and expected available credit capacity will not be sufficient to meet our commitments as they come due and, absent a material improvement in oil and natural gas prices, we will not be able to remain in compliance with our current debt covenants unless we are able to successfully increase our liquidity. We will therefore need to complete certain transactions, including management of debt capital structure and additional potential asset sales, to have sufficient liquidity to satisfy these obligations.  As previously announced, in early 2015 we engaged Evercore and Kirkland & Ellis to assist with reviewing all options to improve our liquidity profile and strengthen our balance sheet. These efforts continue in earnest and we are considering all available strategic alternatives and financing possibilities, including, without limitation, the incurrence of additional secured indebtedness and the exchange or refinancing of existing obligations.   We can provide no assurance that the discussions will result in the completion of a transaction, or that any completed transaction will result in sufficient liquidity to satisfy our obligations.

 

Operations Update

 

Mississippian Lime

 

At March 31, 2015, our Mississippian Lime area assets consisted of approximately 81,200 net prospective acres in the Mississippian Lime trend, with 67,050 net acres in Woods and Alfalfa Counties of Oklahoma, which we currently believe is the core of the trend. We currently plan to develop these liquids rich properties using horizontal wells. We also own approximately 12,600 net acres in Lincoln County, Oklahoma, which currently produces from, and is also prospective in, the Hunton formation. As of March 31, 2015, we held an average working interest and average net revenue interest of 68% and 54%, respectively in this area.

 

For the three months ended March 31, 2015 and December 31, 2014, our average daily production from the Mississippian Lime area was as follows:

 

 

 

Three Months Ended
March 31, 2015

 

Three Months Ended
December 31, 2014

 

Increase in
Production

 

 

 

 

 

 

 

 

 

Average daily production:

 

 

 

 

 

 

 

Oil (Bbls)

 

10,675

 

10,060

 

6

%

Natural gas liquids (Bbls)

 

5,367

 

4,809

 

12

%

Natural gas (Mcf)

 

62,933

 

61,025

 

3

%

Net Boe/day

 

26,531

 

25,039

 

6

%

 

The following table shows our total number of horizontal wells spud and brought into production in the Mississippian Lime area during the first quarter of 2015:

 

 

 

Total Number of
Gross Horizontal
Wells Spud (1)

 

Total Number of
Gross Horizontal
Wells Brought
into Production

 

Mississippian Lime

 

18

 

26

 

 


(1)  We had four rigs drilling in the Mississippian Lime horizontal well program at March 31, 2015. Of the 18 wells spud, six were producing, eight were awaiting completion and four were being drilled at quarter-end.

 

Overall production increased by 6% versus the fourth quarter of 2014 as a result of our drilling and completion activity. The first quarter of 2015 was also favorably impacted by 26 gross wells that were not online or completed at December 31, 2014, and were brought into production during the first quarter of 2015.

 

In the first quarter of 2015, we invested approximately $88.9 million on completions and drilling new wells.

 

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Anadarko Basin

 

At March 31, 2015, our Anadarko Basin assets consisted of approximately 114,200 net acres, of which 82,800 acres were located in Texas and 31,400 acres were located in western Oklahoma. We held an average working interest and average net revenue interest of 66% and 51%, respectively, in this area as of March 31, 2015.

 

For the three months ended March 31, 2015 and December 31, 2014, our average daily production from our Anadarko Basin area was as follows:

 

 

 

Three Months Ended
March 31, 2015

 

Three Months Ended
December 31, 2014

 

Decrease in
Production

 

 

 

 

 

 

 

 

 

Average daily production:

 

 

 

 

 

 

 

Oil (Bbls)

 

3,028

 

3,343

 

-9

%

Natural gas liquids (Bbls)

 

1,240

 

1,703

 

-27

%

Natural gas (Mcf)

 

12,734

 

13,749

 

-7

%

Net Boe/day

 

6,390

 

7,337

 

-13

%

 

During the three months ended March 31, 2015, we brought three wells online. We did not spud any wells in the Anadarko area during that time and did not have any operated drilling rigs in the area during the three months ended March 31, 2015.

 

Overall production decreased by 13% versus the fourth quarter of 2014 primarily due to base production declines and our decision to suspend our drilling in this area due to the commodity price environment.  During the first quarter of 2015, we invested approximately $3.2 million on completions and capital workover programs.

 

Gulf Coast

 

In our Gulf Coast region, our current acreage position and evaluation efforts are concentrated in Louisiana in the Wilcox interval of the Upper Gulf Coast Tertiary trend.

 

On May 1, 2014, we closed on the sale of producing properties and undeveloped acreage in the Pine Prairie Field area of Evangeline Parish, Louisiana for estimated net proceeds of $147.5 million in cash, after post-closing adjustments.

 

On April 21, 2015, we closed on the sale of producing properties and undeveloped acreage in the Dequincy area located in Beauregard and Calcasieu Parishes, Louisiana for net proceeds of approximately $42 million, net of customary closing adjustments. Following the sale of our Dequincy assets, we no longer have any proved reserves or producing properties in our Gulf Coast area. After giving effect to the sale of our Dequincy assets, we had approximately 33,350 net acres in the trend at March 31, 2015.

 

For the three months ended March 31, 2015 and December 31, 2014, our average daily production from the Gulf Coast area was as follows:

 

 

 

Three Months Ended
March 31, 2015

 

Three Months Ended
December 31, 2014

 

Decrease in
Production

 

 

 

 

 

 

 

 

 

Average daily production:

 

 

 

 

 

 

 

Oil (Bbls)

 

858

 

959

 

-11

%

Natural gas liquids (Bbls)

 

274

 

278

 

-1

%

Natural gas (Mcf)

 

664

 

911

 

-27

%

Net Boe/day

 

1,243

 

1,388

 

-10

%

 

Overall production decreased by 10% versus the fourth quarter of 2014, due to continued base production declines as we have devoted our capital to developing our Mississippian Lime asset.

 

In the first quarter of 2015, we invested approximately $0.9 million in the Gulf Coast area primarily for workovers and other projects intended to stem base production decline in the Dequincy area. No operated wells were spud or brought into production in our Gulf Coast area of operation during the first quarter of 2015; one well was spud during the quarter as part of the exploration agreement with PetroQuest.

 

Capital Expenditures

 

During the three months ended March 31, 2015, we incurred operational capital expenditures of $93.0 million, including capitalized interest, which consisted primarily of:

 

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For the Three
Months Ended
March 31, 2015

 

Drilling and completion activities

 

$

91,051

 

Acquisition of acreage and seismic data

 

1,924

 

Operational capital expenditures incurred

 

$

92,975

 

Capitalized G&A, office, ARO & other

 

1,760

 

Capitalized interest

 

984

 

Total capital expenditures incurred

 

$

95,719

 

 

Operational capital expenditures by area were as follows:

 

 

 

For the Three
Months Ended
March 31, 2015

 

Mississippian Lime

 

88,889

 

Anadarko Basin

 

3,164

 

Gulf Coast

 

922

 

Total operational capital expenditures incurred

 

$

92,975

 

 

We expect to invest between $250 million to $275 million of capital for exploration, development and lease and seismic acquisition during the year ended December 31, 2015.

 

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, our cash flows, 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” 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 and terms of such capital, our current financial condition, expectations regarding the future price for oil and natural gas, 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 or workover 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.

 

We follow the full cost method of accounting for our oil and gas properties.  In the first quarter of 2015, the results of our full cost “ceiling test” required us to recognize a before tax impairment of our oil and gas properties of $174.7 million. While this impairment did not impact cash flow from operating activities, it did reduce our earnings and shareholders’ equity.  We will likely be required to recognize additional impairments of oil and gas properties in future periods if we continue to experience an extended period of low commodity prices, which will result in a downward adjustment to our estimated proved reserves and the associated present value of

 

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estimated future net revenues, or if we incur actual development costs in excess of those estimates utilized in preparing our reserve reports.  Additionally, the expiration of unevaluated acreage leaseholds may increase the probability of future impairments, as the costs associated with the expiring leases would be immediately included in the full cost pool and become subject to the ceiling test limitation without any corresponding increase in reserves or future net revenues.

 

Results of Operations

 

The following tables summarize our revenue, production and price data for the periods indicated. Prior to May 1, 2014, our operating results include production, revenue and lease operating expenses attributable to our Pine Prairie field, the sale of which closed effective May 1, 2014.  Where applicable, in the following discussion, we have noted normalized production, revenue, lease operating expenses and percentages for prior periods as though the Pine Prairie Disposition occurred as of the beginning of that period.

 

Revenues

 

 

 

For the Three Months Ended March 31

 

 

 

2015

 

2014

 

 

 

(in thousands)

 

REVENUES:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

59,257

 

66

%

$

116,222

 

70

%

Natural gas liquid sales

 

11,010

 

12

%

25,519

 

15

%

Natural gas sales

 

19,172

 

22

%

25,385

 

15

%

Total oil, natural gas liquids, and natural gas sales

 

89,439

 

100

%

167,126

 

100

%

 

 

 

 

 

 

 

 

 

 

Net cash received (paid) for commodity derivative contracts

 

52,608

 

246

%

(14,810

)

65

%

Unrealized losses on commodity derivative contracts, net

 

(31,236

)

-146

%

(7,863

)

35

%

Gains (losses) on commodity derivative contracts - net

 

21,372

 

100

%

(22,673

)

100

%

 

 

 

 

 

 

 

 

 

 

Other

 

387

 

 

 

209

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

$

111,198

 

 

 

$

144,662

 

 

 

 

Production

 

 

 

For the Three Months
Ended March 31,

 

 

 

2015

 

2014

 

% Change

 

PRODUCTION DATA:

 

 

 

 

 

 

 

Oil (MBbls)

 

1,310

 

1,208

 

8

%

Natural gas liquids (MBbls)

 

619

 

532

 

16

%

Natural gas (MMcf)

 

6,870

 

5,224

 

32

%

Oil equivalents (MBoe)

 

3,075

 

2,610

 

18

%

 

 

 

 

 

 

 

 

Oil (Boe/day)

 

14,561

 

13,417

 

9

%

Natural gas liquids (Boe/day)

 

6,881

 

5,912

 

16

%

Natural gas (Mcf/day)

 

76,331

 

58,048

 

31

%

Average daily production (Boe/d)

 

34,164

 

29,004

 

18

%

 

Prices

 

 

 

For the Three Months
Ended March 31,

 

 

 

2015

 

2014

 

% Change

 

AVERAGE SALES PRICES:

 

 

 

 

 

 

 

Oil, without realized derivatives (per Bbl)

 

$

45.22

 

$

96.25

 

-53

%

Oil, with realized derivatives (per Bbl)

 

$

79.45

 

87.06

 

-9

%

Natural gas liquids, without realized derivatives (per Bbl)

 

$

17.78

 

47.96

 

-63

%

Natural gas liquids, with realized derivatives (per Bbl)

 

$

17.78

 

47.79

 

-63

%

Natural gas, without realized derivatives (per Mcf)

 

$

2.79

 

4.86

 

-43

%

Natural gas, with realized derivatives (per Mcf)

 

$

3.92

 

4.16

 

-6

%

 

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Table of Contents

 

Three Months Ended March 31, 2015 as Compared to the Three Months Ended March 31, 2014

 

Oil, natural gas liquids and natural gas sales revenues

 

Our oil, NGL and natural gas sales revenues decreased by $77.7 million, or 46% to $89.4 million during the three months ended March 31, 2015, as compared to $167.1 million during the three months ended March 31, 2014. After normalizing for the Pine Prairie Disposition as if the disposition occurred on January 1, 2014, revenues decreased by $63.4 million, or 41%.

 

Our oil sales revenues decreased by $57.0 million, or 49%, to $59.2 million during the three months ended March 31, 2015, as compared to $116.2 million for the three months ended March 31, 2014. After normalizing for the Pine Prairie Disposition as if the disposition occurred on January 1, 2014, oil sales revenues decreased by $44.5 million and 43%. Oil volumes sold increased 1,144 Boe/day, or 9%, to 14,561 Boe/day for the three months ended March 31, 2015, from 13,417 Boe/day for the three months ended March 31, 2014. This increase in oil volumes sold was attributable to increased production quarter over quarter in the Mississippian Lime area of 4,594 Boe/day, partially offset by a 1,315 Boe/day decrease in production volumes from our Anadarko Basin area and a 2,135 Boe/day decrease in production from our Gulf Coast area, of which 1,357 Boe/day was related to Pine Prairie. The overall improvement in oil sales volumes of 1,144 Boe/day resulted in approximately $9.8 million in additional oil sales revenues. Average oil sales prices, without realized derivatives, decreased by $51.03 per barrel, or 53%, to $45.22 per barrel during the three months ended March 31, 2015 as compared to $96.25 per barrel for the three months ended March 31, 2014. This price variance resulted in a decrease in oil sales revenue of approximately $66.9 million during the three months ended March 31, 2015, as measured against the comparable period in 2014.

 

Our NGL sales revenues decreased by $14.5 million, or 57%, to $11.0 million during the three months ended March 31, 2015, as compared to $25.5 million for the three months ended March 31, 2014. After normalizing for the Pine Prairie Disposition as if the disposition occurred on January 1, 2014, NGL sales revenues decreased by $13.3 million, or 55%. NGL volumes sold increased 969 Boe/day, or 16%, to 6,881 Boe/day for the three months ended March 31, 2015, from 5,912 Boe/day for the three months ended March 31, 2014. This increase in NGL volumes sold was attributable to the increased production quarter over quarter in the Mississippian Lime area of 1,870 Boe/day, partially offset by a 453 Boe/day decrease in production volumes from our Anadarko Basin area and a 448 Boe/day decrease in production from our Gulf Coast area, of which 270 Boe/day was related to Pine Prairie. The overall improvement in NGL sales volumes of 969 Boe/day resulted in approximately $4.2 million in additional NGL sales revenues. Average NGL sales prices, without realized derivatives, decreased by $30.18 per barrel, or 63%, to $17.78 per barrel during the three months ended March 31, 2015 as compared to $47.96 per barrel for the corresponding period in 2014. This price variance resulted in a decrease in NGL sales revenue of approximately $18.7 million during the three months ended March 31, 2015 as measured against the comparable period in 2014.

 

Our natural gas sales revenues decreased by $6.2 million, or 24%, to $19.2 million during the three months ended March 31, 2015, as compared to $25.4 million for the three months ended March 31, 2014. After normalizing for the Pine Prairie Disposition as if the disposition occurred on January 1, 2014, natural gas sales revenues decreased $5.4 million, or 22%. Natural gas volumes sold increased 18,283 Mcf/day or 31%, to 76,331 Mcf/day for the three months ended March 31, 2015, from 58,048 Mcf/day for the three months ended March 31, 2014. This increase in natural gas volumes sold was attributable to increased production of 22,117 Mcf/day in the Mississippian Lime area, partially offset by a decrease in production of 1,306 Mcf/day from our Anadarko Basin area and 2,528 Mcf/day from our Gulf Coast area, of which 1,791 Mcf/day was related to Pine Prairie. The overall improvement in natural gas sales volumes of 18,283 Mcf/day resulted in approximately $8.0 million in additional natural gas sales revenues. Average natural gas sales prices, without realized derivatives, decreased by $2.07 per Mcf, or 43%, to $2.79 per Mcf during the three months ended March 31, 2015 as compared to $4.86 per Mcf for the three months ended March 31, 2014. This price variance resulted in a decrease in natural gas sales revenue of approximately $14.2 million during the three months ended March 31, 2015, as measured against the comparable period in 2014.

 

Gains/losses on commodity derivative contracts - net

 

Our mark-to-market (“MTM”) derivative positions moved from an unrealized loss of $7.9 million for the three months ended March 31, 2014 to an unrealized loss of $31.2 million for the three months ended March 31, 2015. The NYMEX WTI closing price on March 31, 2015 was $47.60 per barrel compared to a closing price of $101.58 per barrel on March 31, 2014. At March 31, 2015, our oil derivatives have contract prices that range from $83.15 to $92.61 per barrel and extend through the fourth quarter of 2015. (See Note 5 in Item 1. Financial Statements.)

 

Cash receipts for the settlements of derivatives were $52.6 million for the three months ended March 31, 2015 as compared to cash payments for the settlement of derivatives of $14.8 million during the three months ended March 31, 2014.  The following table presents cash receipts for the settlements of derivatives by type of commodity contract for the three months ended March 31, 2015:

 

 

 

For the Three Months
Ended March 31, 2015

 

 

 

Total

 

Average
Sales Price

 

 

 

(in thousands)

 

 

 

Oil commodity contracts

 

$

44,857

 

$

79.45

 

Natural gas commodity contracts

 

7,751

 

3.92

 

Net cash received for commodity derivative contracts

 

$

52,608

 

 

 

 

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Table of Contents

 

Cash settlements, as presented in the table above, represent realized gains or losses related to our derivative instruments. In addition to cash settlements, we also recognize fair value changes on our derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

 

Operating Expenses

 

The table below presents a comparison of our expenses on an absolute dollar basis and a per Boe basis. Depending on the relevance, our discussion may reference expenses on an absolute dollar basis, a per Boe basis, or both.

 

 

 

Three Months Ended March 31

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(in thousands)

 

(per Boe)

 

EXPENSES:

 

 

 

 

 

 

 

 

 

Lease operating and workover

 

$

23,262

 

$

20,127

 

$

7.56

 

$

7.71

 

Gathering and transportation

 

3,438

 

2,855

 

1.12

 

1.09

 

Severance and other taxes

 

3,565

 

7,647

 

1.16

 

2.93

 

Asset retirement accretion

 

445

 

497

 

0.14

 

0.19

 

Depreciation, depletion, and amortization

 

58,428

 

66,901

 

19.00

 

25.63

 

Impairment of oil and gas properties

 

174,667

 

86,471

 

56.80

 

33.13

 

General and administrative

 

11,654

 

11,684

 

3.79

 

4.48

 

Acquisition and transaction costs

 

 

128

 

 

0.05

 

Advisory fees

 

1,743

 

 

0.57

 

 

Other

 

97

 

330

 

0.03

 

0.13

 

Total expenses

 

$

277,299

 

$

196,640

 

$

90.17

 

$

75.34

 

 

Three Months Ended March 31, 2015 as Compared to the Three Months Ended March 31, 2014

 

Lease operating and workover expenses

 

Lease operating and workover expenses increased $3.1 million, or 15%, to $23.2 million for the three months ended March 31, 2015 compared to $20.1 million for the three months ended March 31, 2014. After normalizing for the Pine Prairie Disposition, lease operating and workover expenses increased $5.5 million, or 31%, largely as a result of increased well count resulting in higher saltwater disposal costs (primarily in our Mississippian Lime area) and higher surface facilities maintenance and repairs in both the Mississippian Lime and Anadarko Basin areas. In the Anadarko Basin we experienced increased artificial lift maintenance and compressor rental costs. We have begun a program to reduce these costs by evaluating our artificial lift mechanisms in the Anadarko Basin and, where appropriate, replacing gas lifts with rod pump mechanisms, which should reduce these costs in future periods. Lease operating and workover expenses decreased to $7.56 per Boe for the three months ended March 31, 2015, a decrease of $0.15, or 2%, over the $7.71 per Boe for the three months ended March 31, 2014.

 

Gathering and transportation

 

Gathering and transportation expenses increased $0.5 million, or 17% to $3.4 million for the three months ended March 31, 2015 compared to $2.9 million for the three months ended March 31, 2014, due to a corresponding increase in production from our Mississippian Lime area.

 

Severance and other taxes

 

 

 

Three Months
Ended March 31

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Total oil, natural gas, and natural gas liquids sales

 

$

89,439

 

$

167,126

 

 

 

 

 

 

 

Severance taxes

 

1,782

 

5,809

 

Ad valorem and other taxes

 

1,783

 

1,838

 

Severance and other taxes

 

$

3,565

 

$

7,647

 

 

 

 

 

 

 

Severance taxes as a percentage of sales

 

2.0

%

3.5

%

Severance and other taxes as a percentage of sales

 

4.0

%

4.6

%

 

Severance taxes decreased $4.0 million, or 69%, to $1.8 million for the three months ended March 31, 2015, as compared to $5.8 million for the three months ended March 31, 2014. Severance taxes as a percentage of sales changed from 3.5% for the three months ended March 31, 2014 to 2.0% for the corresponding 2015 period due to lower effective severance tax rates in our Mississippian Lime and lower production period over period in the relatively higher tax Gulf Coast region. Ad valorem taxes were flat for the three months ended March 31, 2015 and 2014 at $1.8 million.

 

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Depreciation, depletion and amortization (“DD&A”)

 

DD&A expense decreased $8.5 million, or 13%, to $58.4 million for the three months ended March 31, 2015 compared to $66.9 million for the three months ended March 31, 2014. The decrease in DD&A expense was driven by downward revisions in our proved undeveloped reserves from March 31, 2014, which decreased estimated finding and developments costs and as a result, reduced our DD&A expense. Consequently, the DD&A rate per Boe also decreased from $25.63 per Boe for the three months ended March 31, 2014 to $19.00 per Boe for the three months ended March 31, 2015.

 

Impairment of oil and gas properties

 

We recorded pre-tax impairment expense related to our oil and natural gas properties for the three months ended March 31, 2015 and 2014 of $174.7 million and $86.5 million, respectively, as a result of our full-cost ceiling test. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of costs associated with our oil and natural gas properties that can be capitalized in our condensed consolidated balance sheets. The impairment expense for the three months ended March 31, 2015 was due to a decrease in value of our proven oil and natural gas reserves as a result of an extended period of low commodity prices.  The impairment expense for three months ended March 31, 2014 was largely due to the transfer of unevaluated property costs to the full cost pool during the first quarter of 2014. During the three months ended March 31, 2014, we transferred $21.4 million and $38.1 million related to Mississippian Lime and Anadarko Basin areas, respectively, as we released acreage that did not present the best near term development potential.

 

General and administrative (“G&A”)

 

Our G&A expenses were $11.7 million for the three months ended March 31, 2015 and 2014. In the three months ended March 31, 2015, approximately $1.7 million in G&A was attributable to severance related payments due to the Houston office closure.

 

Acquisition and transaction costs

 

We did not incur any acquisition and transaction costs for the three months ended March 31, 2015, compared to $0.1 million for the three months ended March 31, 2014. For the 2014 period, these costs represent our expenses related to the Pine Prairie Disposition.

 

Advisory fees

 

As discussed previously, we are analyzing options to improve our financial flexibility and provide additional long-term liquidity.  As part of that process, we have engaged various advisors to assist us.  For the three months ended March 31, 2015, the Company incurred approximately $1.7 million in fees associated with these advisors.  We expect to incur additional significant costs during the remainder of 2015 for such advisors.

 

Other

 

Other operating expenses for the three months ended March 31, 2015 were $0.1 million, compared to $0.3 million for the three months ended March 31, 2014.  Other operating expenses represent the loss on disposal of, or market value adjustments to, field equipment inventory.

 

Other Income (Expenses)

 

 

 

For the Three Months
Ended March 31,

 

 

 

2015

 

2014

 

 

 

(in thousands)

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

Interest income

 

$

9

 

$

10

 

 

 

 

 

 

 

Interest expense

 

(37,487

)

(38,565

)

Capitalized Interest

 

984

 

4,618

 

Interest expense — net of amounts capitalized

 

(36,503

)

(33,947

)

 

 

 

 

 

 

Total other income (expense)

 

$

(36,494

)

$

(33,937

)

 

Interest expense

 

Three Months Ended March 31, 2015 as Compared to the Three Months Ended March 31, 2014

 

Interest expense for the three months ended March 31, 2015 and 2014 was $37.5 million and $38.6 million, respectively. Our average outstanding balance under our revolving credit facility was $435.2 million during the three months ended March 31, 2015, compared to $401.2 million for the three months ended March 31, 2014, and related to $3.3 million of the total interest expense of $37.5 million for the three months ended March 31, 2015. Of the remainder, $16.2 million was interest incurred under the 2021 Senior Notes, $16.1 million was interest incurred under the 2020 Senior Notes and $1.9 million represented amortization of deferred financing costs. Of the total interest expense for both periods, $1.0 million and $4.6 million was capitalized to oil and gas properties, resulting in $36.5 million and $33.9 million in interest expense, net of capitalized interest, for the three months ended March 31, 2015 and 2014, respectively.

 

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Provision for Income Taxes

 

Three Months Ended March 31, 2015 as Compared to the Three Months Ended March 31, 2014

 

Our income tax benefit was $9.0 million for the three months ended March 31, 2015 compared to a benefit of $2.3 million for the three months ended March 31, 2014. For the three months ended March 31, 2015, the Company’s effective tax rate was approximately 4.5%. The Company’s effective tax rate for the first quarter of 2015 differs from the federal statutory rate of 35% due to the effect of recurring permanent adjustments, state income taxes and changes in the valuation allowance.

 

The Company expects to incur a tax loss in the current year due to the flexibility in deducting or capitalizing current year intangible drilling costs; thus no current income taxes are anticipated to be paid.

 

A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its NOLs are realizable except to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment.

 

Liquidity and Capital Resources

 

Our financial statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. The content below and under “Risks, Uncertainties, and Going Concern” above addresses important factors affecting our financial condition, liquidity and capital resources and debt covenant compliance.

 

At March 31, 2015, our liquidity consisted of approximately $88.4 million of available borrowing capacity under our revolving credit facility and $12 million of cash and cash equivalents.

 

Expenditures for exploration and development of oil and natural gas properties and payments for interest related to our Credit Facility, our 2020 Senior Notes and our 2021 Senior Notes are the primary use of our capital resources and liquidity. We expect to invest between $250 million and $275 million of capital for exploration, development and lease and seismic acquisition during the year ending December 31, 2015. Additionally, we expect to capitalize between $4 million and $6 million of interest expense during that same period. The interest payment obligations are substantial, and the Company is required to pay approximately $32 million in interest on the 2020 Senior Notes on each of April 1 and October 1 and approximately $32 million in interest on the 2021 Senior Notes on each of June 1 and December 1. Our future success in growing proved reserves and production and meeting our interest obligations will be highly dependent on our ability to access additional outside sources of capital, via either the debt or equity markets, through growth in our reserve based credit facility or by securing other external sources of funding. As part of that process, in April 2015, we closed a purchase and sale agreement covering the sale of our remaining producing assets in Louisiana for total consideration of approximately $42 million cash, net of customary closing adjustments. The net proceeds will be used to repay a portion of our outstanding borrowings under our Credit Facility and for general corporate purposes.

 

We plan to continue pursuing additional options that would improve our financial flexibility and provide additional long term liquidity, including the sale of other non-core assets and possibly joint ventures or farm outs on our properties and management of our debt capital structure. As previously announced, in early 2015 we engaged Evercore and Kirkland & Ellis to assist with reviewing all options to improve our liquidity profile and strengthen our balance sheet. These efforts continue in earnest and we are considering all available strategic alternatives and financing possibilities, including, without limitation, the incurrence of additional secured indebtedness and the exchange or refinancing of existing obligations.  We can provide no assurance that the discussions will result in the completion of a transaction, or that any completed transaction will result in sufficient liquidity to satisfy our obligations.

 

Significant Sources of Capital

 

Reserve-based Credit Facility

 

Our credit facility consists of a $750 million senior revolving credit facility with a borrowing base supported by our Mississippian Lime and Anadarko Basin oil and gas assets. On September 30, 2014, we entered into an Assignment and Borrowing Base Increase Agreement that increased the borrowing base under the Credit Facility from $475 million to $525 million. The borrowing base was reaffirmed on March 24, 2015 at $525 million, with no reduction upon the closing in April of the Sale of Dequincy. At March 31, 2015 we had drawn $435.2 million on our Credit Facility and had outstanding letters of credit obligations totaling $1.4 million.

 

The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of our oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon our borrowing base utilization, between 2.00% and 3.00% per annum. At March 31, 2015 and 2014, the weighted average interest rate was 3.0% and 2.7%, respectively.

 

In addition to interest expense, the Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.50% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

 

The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by us 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 Credit Facility, we are required to repay the amount by which the principal balance of our outstanding loans and our letter of credit obligations exceeds our redetermined borrowing base. We are permitted to make such repayment in six equal

 

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Table of Contents

 

successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction.

 

The Credit Facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of debt to EBITDA (i.e. leverage ratio) and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. Pursuant to the Sixth Amendment, we are required to maintain a leverage ratio of not more than 4.5 to 1.0 through December 31, 2015 and 4.0 to 1.0 for each quarter thereafter. The Credit Facility also limits our ability to make any dividends, distributions or redemptions.

 

As of March 31, 2015, we were in compliance with the minimum current ratio and the ratio of net debt to EBITDA covenants as set forth in the Credit Facility. Our current ratio at March 31, 2015 was 1.0 to 1.0. As calculated for covenant compliance purposes, our current assets exceeded our current liabilities by approximately $1.5 million at March 31, 2015. At March 31, 2015, our ratio of debt to EBITDA was 3.7 to 1.0.

 

2020 Senior Notes

 

On October 1, 2012, we issued $600 million in aggregate principal amount of 10.75% senior notes due in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). In October 2013, these notes were exchanged for an equal principal amount of notes with identical terms other than registration under the Securities Act and the omission of restrictions on transfer, registration rights and provisions for additional interest (the “2020 Senior Notes”). The 2020 Senior Notes were co issued on a joint and several basis by us and our wholly owned subsidiary, Midstates Sub. We do not have any operations or independent assets other than our 100% ownership interest in Midstates Sub and we have no other subsidiaries. The 2020 Senior Notes Indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to us or limit our ability to advance loans to Midstates Sub.

 

The 2020 Senior Notes Indenture contains covenants that, among other things, restrict our ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with our affiliates; (vii) consolidate, merge or sell substantially all of our assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business we conduct and (x) enter into agreements restricting the ability of our current and any future subsidiaries to pay dividends.

 

2021 Senior Notes

 

On May 31, 2013, we issued $700 million in aggregate principal amount of 9.25% senior notes due 2021. In October 2013, these notes were exchanged for an equal principal amount of notes with identical terms other than registration under the Securities Act and the omission of restrictions on transfer, registration rights and provisions for additional interest (the “2021 Senior Notes”).

 

The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes.

 

The 2021 Senior Notes were co issued on a joint and several basis by us and our wholly owned subsidiary, Midstates Sub. The 2021 Senior Notes indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to us or limit our ability to advance loans to Midstates Sub.

 

The terms of the in the 2021 Senior Notes Indenture are substantially identical to those of the 2020 Senior Notes discussed above.

 

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. 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.

 

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.”.

 

The following information highlights the significant period-to-period variances in our cash flow amounts (table in thousands):

 

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Table of Contents

 

 

 

For the Three Months
Ended March 31,

 

 

 

2015

 

2014

 

Net cash provided by operating activities

 

$

113,017

 

$

105,409

 

Net cash used in investing activities