S-4 1 d477200ds4.htm FORM S-4 Form S-4
Table of Contents

As filed with the Securities and Exchange Commission on February 14, 2013

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Samson Resources Corporation

(Exact name of registrant parent guarantor as specified in its charter)

 

 

SEE TABLE OF ADDITIONAL REGISTRANTS

 

 

 

Delaware   1311   45-3991227
(State or other jurisdiction
of incorporation)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer Identification
Number)

 

 

Samson Plaza

Two West Second Street

Tulsa, OK 74103-3103

(918) 591-1791

(Address, including zip code, and telephone number, including area code, of registrants’ principal executive offices)

 

 

Michael G. Daniel

Samson Resources Corporation

Vice President-General Counsel

Two West Second Street

Tulsa, OK 74103-3103

(918) 591-1791

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

With a copy to:

Edward P. Tolley III, Esq.

Simpson Thacher & Bartlett LLP

425 Lexington Avenue

New York, New York 10017-3954

Telephone: (212) 455-2000

Facsimile: (212) 455-2502

 

 

Approximate date of commencement of proposed exchange offer: As soon as practicable after this Registration Statement is declared effective.

If the securities being registered on this form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, please check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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 definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Company Tender Offer)  ¨

Exchange Act Rule 14d-1(d) (Cross Border Third-Party Tender Offer)  ¨

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of
Securities to be Registered
  Amount
to be
Registered
  Proposed
Maximum
Offering Price
Per Note
  Proposed
Maximum
Aggregate
Offering Price(1)
  Amount of
Registration Fee

9.750% Senior Notes due 2020

  $2,250,000,000   100%   $2,250,000,000   $306,900

Guarantees of 9.750% Senior Notes due 2020(2)

  N/A   N/A   N/A   N/A(3)

 

 

 

(1) Estimated solely for the purpose of calculating the registration fee under Rule 457(f) of the Securities Act of 1933, as amended (the “Securities Act”).
(2) See inside facing page for table of additional registrants.
(3) Pursuant to Rule 457(n) under the Securities Act, no separate filing fee is required for the guarantees.

 

 

The Registrants hereby amend this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrants shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents

Table of Additional Registrants

 

Exact Name of Registrant as

Specified in its Charter

(or Other Organizational Document)

     State or Other
Jurisdiction of
Incorporation
or Organization
     I.R.S. Employer
Identification
Number
    

Address, Including Zip Code,

and Telephone Number,

Including Area Code,

of

Principal

Executive Offices

Samson Investment Company (“Issuer”)      Nevada      73-1281091     

Samson Plaza

Two West Second St.

Tulsa, OK 74103-3103

(918)591-1791

Geodyne Resources, Inc.      Delaware      73-1052703     

Samson Plaza

Two West Second St.

Tulsa, OK 74103-3103

(918)591-1791

Samson Contour Energy Co.      Delaware      76-0447267     

Samson Plaza

Two West Second St.

Tulsa, OK 74103-3103

(918)591-1791

Samson Contour Energy E&P, LLC      Delaware      76-0082502     

Samson Plaza

Two West Second St.

Tulsa, OK 74103-3103

(918)591-1791

Samson Holdings, Inc.      Delaware      73-1498587     

Samson Plaza

Two West Second St.

Tulsa, OK 74103-3103

(918)591-1791

Samson Lone Star, LLC      Delaware      45-3939455     

Samson Plaza

Two West Second St.

Tulsa, OK 74103-3103

(918)591-1791

Samson Resources Company      Oklahoma      73-0928007     

Samson Plaza

Two West Second St.

Tulsa, OK 74103-3103

(918)591-1791

Samson-International, Ltd.      Oklahoma      73-1404039     

Samson Plaza

Two West Second St.

Tulsa, OK 74103-3103

(918)591-1791


Table of Contents

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED FEBRUARY 14, 2013

PRELIMINARY PROSPECTUS

 

LOGO

SAMSON RESOURCES CORPORATION

Offer to Exchange (the “Exchange Offer”)

$2,250,000,000 aggregate principal amount of 9.750% Senior Notes due 2020 (the “exchange notes”) which have been registered under the Securities Act of 1933, as amended, (the “Securities Act”) for any and all outstanding unregistered 9.750% Senior Notes due 2020 (the “outstanding notes”).

 

 

We are conducting the exchange offer in order to provide you with an opportunity to exchange your unregistered outstanding notes for freely tradable notes that have been registered under the Securities Act.

The Exchange Offer

 

   

We will exchange all outstanding notes that are validly tendered and not validly withdrawn for an equal principal amount of exchange notes that are freely tradable.

 

   

You may withdraw tenders of outstanding notes at any time prior to the expiration date of the exchange offer.

 

   

The exchange offer expires at 12:00 a.m., New York City time, on             , 2013, unless extended. We do not currently intend to extend the expiration date.

 

   

The exchange of outstanding notes for exchange notes in the exchange offer will not constitute taxable events to holders for United States federal income tax purposes.

 

   

The terms of the exchange notes to be issued in the exchange offer are substantially identical to the outstanding notes, except that the exchange notes will be freely tradable.

Results of the Exchange Offer

 

   

The exchange notes may be sold in the over-the-counter market, in negotiated transactions or through a combination of such methods. We do not plan to list the exchange notes on a national market.

All untendered outstanding notes will continue to be subject to the restrictions on transfer set forth in the outstanding notes and in the indenture governing the notes. In general, the outstanding notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the exchange offer, we do not currently anticipate that we will register the outstanding notes under the Securities Act.

See “Risk Factors” beginning on page 9 of this prospectus for a discussion of certain risks that you should consider before participating in the exchange offer.

 

 

Neither the Securities and Exchange Commission (the “SEC”) nor any state securities commission has approved or disapproved of the exchange notes to be distributed in the exchange offer or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

 

 

The date of this prospectus is             , 2013.


Table of Contents

You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different information. The prospectus may be used only for the purposes for which it has been published, and no person has been authorized to give any information not contained herein. If you receive any other information, you should not rely on it. We are not making an offer of these securities in any state where the offer is not permitted.

 

 

Table of Contents

 

     Page  

Basis of Presentation

     ii   

Prospectus Summary

     1   

Risk Factors

     9   

Cautionary Statement Regarding Forward-Looking Statements

     39   

Use of Proceeds

     41   

Capitalization

     42   

Ratio of Earnings to Fixed Charges

     43   

Selected Historical Consolidated Financial Data

     44   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     47   

Business

     78   

Management

     101   

Executive Compensation

     106   

Security Ownership of Certain Beneficial Owners

     122   

Certain Relationships and Related Party Transactions

     124   

Description of Other Indebtedness

     127   

The Exchange Offer

     132   

Description of Notes

     142   

Certain United States Federal Income Tax Consequences

     205   

Certain ERISA Considerations

     206   

Plan of Distribution

     208   

Legal Matters

     209   

Experts

     209   

Available Information

     210   

Index to Financial Statements

     F-1   

Annex A: Glossary of Natural Gas and Oil Terms

     A-1   

 

i


Table of Contents

Basis of Presentation

On November 22, 2011, Samson Resources Corporation, a company primarily controlled by affiliates of Kohlberg Kravis Roberts & Co. L. P. (“KKR”), entered into a stock purchase agreement (the “SPA”) with Samson Investment Company and its selling stockholders (the “Acquisition”). As a result of the Acquisition, KKR and certain other co-investors, through Samson Resources Corporation, beneficially own substantially all of the issued and outstanding capital stock of Samson Investment Company. The Acquisition closed on December 21, 2011 and we financed the Acquisition, repaid all of our outstanding long-term indebtedness and paid related fees and expenses with: (i) approximately $1,345.0 million of borrowings under a reserve-based borrowing base revolving credit facility (the “RBL Revolver”); (ii) $2,250.0 million of borrowings under a syndicated senior unsecured bridge facility (the “Bridge Facility”); (iii) $4,145.0 million of equity capital from KKR and the other investors; and (iv) $180.0 million aggregate liquidation preference of cumulative redeemable preferred stock, par value $0.10 per share (the “Cumulative Preferred Stock”), issued by Samson Resources Corporation to the selling stockholders (collectively, the “Original Financing”).

In addition, prior to the consummation of the Acquisition, Samson Investment Company completed a reorganization as a result of which certain assets and liabilities used by its Gulf Coast and Offshore regions (the “Gulf Coast and Offshore assets”) were retained by the selling stockholders. The Gulf Coast and Offshore assets were not included in the Acquisition.

On February 8, 2012, Samson Investment Company issued the outstanding notes and used the proceeds therefrom to repay outstanding borrowings under our Bridge Facility in full and pay fees and expenses incurred in connection therewith.

The issuance of the outstanding notes, the Acquisition, the Original Financing, the Gulf Coast and Offshore Reorganization, the repayment of the outstanding borrowings under our Bridge Facility in full and the payment of fees and expenses in connection therewith are collectively referred to as the “Transactions.”

Unless the context requires otherwise, in this prospectus, references to (i) “Samson,” the “Company,” “we,” “us” and “our” refer to Samson Resources Corporation and its consolidated subsidiaries after the consummation of the Transactions, (ii) “Samson Investment Company” refer to Samson Investment Company, the issuer of the notes, (iii) “Predecessor” refer to Samson Investment Company prior to the consummation of the Acquisition on December 21, 2011, (iv) the “Second Lien Term Loan” refer to the $1,000.0 million second lien term loan agreement, dated as of September 25, 2012, and (v) the “notes” refer to the outstanding notes and the exchange notes collectively.

In addition, on August 1, 2012, we changed our fiscal year end from June 30 to December 31. The financial statements herein include the financial statements of Samson Resources Corporation for the nine months ended September 30, 2012, our latest interim period, for the period from inception (November 14, 2011) through December 31, 2011, and the financial statements of the Predecessor for the nine months ended September 30, 2011, the period from July 1, 2011 through December 21, 2011, and for the fiscal years ending June 30, 2011, 2010 and 2009, respectively.

 

ii


Table of Contents

Prospectus Summary

This summary highlights key aspects of the information contained elsewhere in this prospectus and may not contain all of the information you should consider before investing in the exchange notes. You should read this summary together with the entire prospectus, including the information presented under the heading “Risk Factors” and the information in the historical financial statements and related notes appearing elsewhere in this prospectus. For a more complete description of our business, see the “Business” section in this prospectus. In addition, certain statements include forward-looking information that involves risks and uncertainties. See “Cautionary Statement Regarding Forward-Looking Statements.” Certain operational terms used in this prospectus are defined in “Annex A: Glossary of Natural Gas and Oil Terms.”

Our Company

We are a private oil and natural gas company engaged in the development, exploration, acquisition and opportunistic divestiture of crude oil and natural gas properties. We have grown through a disciplined development and exploration drilling program and a series of strategic acquisitions. As of September 30, 2012, we had approximately 2.9 million net acres primarily concentrated in our three core areas of operations, the Rockies, Mid-Continent and East Texas.

We have identified a large multi-year inventory of an estimated 4,594 risked drilling locations in some of the premier resource plays in the United States. We have positions in well-known unconventional oil and liquids-rich plays, including the Bakken and the stacked oil plays within the Powder River and Green River basins in our Rockies region, the Granite Wash, Prue Wash and Cana Woodford plays in our Mid-Continent region, and the horizontal Cotton Valley in our East Texas region. The majority of our capital expenditures have been and are expected to be directed to these opportunities. Our unconventional gas shales include the Haynesville and Bossier plays in our East Texas region where our core acreage is largely held by production.

 

 

Our principal executive offices are located at Samson Plaza, Two West Second Street, Tulsa, OK 74103-3103, and our telephone number at that address is (918) 591-1791. Our Internet address is http://www.samson.com. Information on our web site does not constitute part of this prospectus.

 

 

1


Table of Contents

The Exchange Offer

On February 8, 2012, Samson Investment Company issued in a private offering $2,250,000,000 aggregate principal amount of outstanding notes.

 

General

In connection with the private placement of the outstanding notes, we entered into a registration rights agreement pursuant to which we agreed, under certain circumstances, to use our reasonable best efforts to file a registration statement relating to an offer to exchange the outstanding notes for exchange notes and to consummate the exchange offer within 450 days after the date of original issuance of the outstanding notes. You are entitled to exchange in the exchange offer your outstanding notes for exchange notes which are identical in all material respects to the outstanding notes except:

 

   

the exchange notes have been registered under the Securities Act;

 

   

the exchange notes are not entitled to any registration rights which are applicable to the outstanding notes under the registration rights agreement; and

 

   

the additional interest provisions of the registration rights agreement are not applicable.

 

The Exchange Offer

We are offering to exchange $2,250,000,000 aggregate principal amount of exchange notes which have been registered under the Securities Act for any and all of its outstanding notes.

 

  You may only exchange outstanding notes in minimum denominations of $2,000 and integral multiples of $1,000 in excess of $2,000.

 

Resale

Based on an interpretation by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the exchange notes issued pursuant to the exchange offer in exchange for the outstanding notes may be offered for resale, resold and otherwise transferred by you (unless you are our “affiliate” within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that:

 

   

you are acquiring the exchange notes in the ordinary course of your business; and

 

   

you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the exchange notes.

 

 

If you are a broker-dealer and receive exchange notes for your own account in exchange for outstanding notes that you acquired as a

 

 

2


Table of Contents
 

result of market-making activities or other trading activities, you must acknowledge that you will deliver this prospectus in connection with any resale of the exchange notes. See “Plan of Distribution.”

 

  Any holder of outstanding notes who:

 

   

is our affiliate;

 

   

does not acquire exchange notes in the ordinary course of its business; or

 

   

tenders its outstanding notes in the exchange offer with the intention to participate, or for the purpose of participating, in a distribution of exchange notes

 

  cannot rely on the position of the staff of the SEC enunciated in the Morgan Stanley & Co. Incorporated no action letter (available June 5, 1991) and the Exxon Capital Holdings Corporation no action letter (available May 13, 1988), as interpreted in the Shearman & Sterling no action letter (available July 2, 1993), or similar no-action letters and, in the absence of an exemption therefrom, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the exchange notes.

 

Expiration Date

The exchange offer will expire at 12:00 a.m., New York City time, on                , 2013, unless extended by us. We currently do not intend to extend the expiration date.

 

Withdrawal

You may withdraw the tender of your outstanding notes at any time prior to the expiration of the exchange offer. We will return to you any of your outstanding notes that are not accepted for any reason for exchange, without expense to you, promptly after the expiration or termination of the exchange offer.

 

Conditions to the Exchange Offer

The exchange offer is subject to customary conditions, which we may waive. See “The Exchange Offer—Conditions to the Exchange Offer.”

 

Procedures for Tendering Outstanding Notes

If you wish to participate in the exchange offer, you must complete, sign and date the accompanying letter of transmittal, or a facsimile of such letter of transmittal, according to the instructions contained in this prospectus and the letter of transmittal. You must then mail or otherwise deliver the letter of transmittal, or a facsimile of such letter of transmittal, together with your outstanding notes and any other required documents, to the exchange agent at the address set forth on the cover page of the letter of transmittal.

 

 

If you hold outstanding notes through The Depository Trust Company (“DTC”) and wish to participate in the exchange offer, you must comply with the Automated Tender Offer Program procedures of

 

 

3


Table of Contents
 

DTC by which you will agree to be bound by the letter of transmittal. By signing, or agreeing to be bound by, the letter of transmittal, you will represent to us that, among other things:

 

   

you are not our “affiliate” within the meaning of Rule 405 under the Securities Act;

 

   

you do not have an arrangement or understanding with any person or entity to participate in the distribution of the exchange notes;

 

   

you are acquiring the exchange notes in the ordinary course of your business; and

 

   

if you are a broker-dealer that will receive exchange notes for your own account in exchange for outstanding notes that were acquired as a result of market-making activities, you will deliver a prospectus, as required by law, in connection with any resale of such exchange notes.

 

Special Procedures for Beneficial Owners

If you are a beneficial owner of outstanding notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and you wish to tender those outstanding notes in the exchange offer, you should contact the registered holder promptly and instruct the registered holder to tender those outstanding notes on your behalf. If you wish to tender on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your outstanding notes, either make appropriate arrangements to register ownership of the outstanding notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time and may not be able to be completed prior to the expiration date.

 

Guaranteed Delivery Procedures

If you wish to tender your outstanding notes and your outstanding notes are not immediately available, or you cannot deliver your outstanding notes, the letter of transmittal or any other required documents, or you cannot comply with the procedures under DTC’s Automated Tender Offer Program for transfer of book-entry interests prior to the expiration date, you must tender your outstanding notes according to the guaranteed delivery procedures set forth in this prospectus under “The Exchange Offer—Guaranteed Delivery Procedures.”

 

Effect on Holders of Outstanding Notes

As a result of the making of, and upon acceptance for exchange of all validly tendered outstanding notes pursuant to the terms of the exchange offer, we will have fulfilled a covenant under the registration rights agreement. Accordingly, there will be no increase in the interest rate on the outstanding notes under the circumstances described in the registration rights agreement. If you do not tender your outstanding notes in the exchange offer, you will continue to be

 

 

4


Table of Contents
 

entitled to all the rights and limitations applicable to the outstanding notes as set forth in the indenture, except we will not have any further obligation to you to provide for the exchange and registration of untendered outstanding notes under the registration rights agreement. To the extent that outstanding notes are tendered and accepted in the exchange offer, the trading market for outstanding notes that are not so tendered and accepted could be adversely affected.

 

Consequences of Failure to Exchange

All untendered outstanding notes will continue to be subject to the restrictions on transfer set forth in the outstanding notes and in the indenture. In general, the outstanding notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the exchange offer, we do not currently anticipate that we will register the outstanding notes under the Securities Act.

 

Certain United States Federal Income Tax Consequences

The exchange of outstanding notes for exchange notes in the exchange offer will not constitute taxable events to holders for United States federal income tax purposes. See “Certain United States Federal Income Tax Consequences.”

 

Use of Proceeds

We will not receive any cash proceeds from the issuance of the exchange notes in the exchange offer. See “Use of Proceeds.”

 

Exchange Agent

Wells Fargo Bank, National Association is the exchange agent for the exchange offer. The address and telephone number of the exchange agent are set forth in the section captioned “The Exchange Offer—Exchange Agent.”

 

 

5


Table of Contents

The Exchange Notes

The summary below describes the principal terms of the exchange notes. Certain of the terms and conditions described below are subject to important limitations and exceptions. The “Description of Notes” section of this prospectus contains more detailed descriptions of the terms and conditions of the outstanding notes and exchange notes. The exchange notes will have terms identical in all material respects to the outstanding notes, except that the exchange notes will not contain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement.

 

Issuer

Samson Investment Company.

 

Securities Offered

$2,250,000,000 aggregate principal amount of exchange notes.

 

Maturity Date

The exchange notes will mature on February 15, 2020.

 

Interest Rate

Interest on the exchange notes will be payable in cash and will accrue at a rate of 9.750% per annum.

 

Interest Payment Dates

We will pay interest on the exchange notes on February 15 and August 15. Interest began to accrue from the issue date of the outstanding notes.

 

Ranking

The exchange notes will be unsecured senior obligations and will:

 

   

rank senior in right of payment to any future subordinated indebtedness;

 

   

rank equally in right of payment with all of Samson Investment Company’s and the guarantors’ existing and future senior indebtedness;

 

   

be effectively subordinated to Samson Investment Company’s and the guarantors’ existing and future secured obligations, including indebtedness under the RBL Revolver and the Second Lien Term Loan, to the extent of the value of the assets securing such indebtedness; and

 

   

be structurally subordinated to all existing and future indebtedness and other liabilities of our non-guarantor subsidiaries (other than indebtedness and liabilities owed to one of the non-guarantor subsidiaries).

 

  As of September 30, 2012 (1) the exchange notes and related guarantees would have ranked effectively junior to approximately $2.015 billion of senior secured indebtedness, including indebtedness under the RBL Revolver and the Second Lien Term Loan, (2) there would have been an additional approximately $984 million of unutilized capacity under the RBL Revolver (before giving effect to $1.1 million of outstanding letters of credit, which reduce availability) and (3) the non-guarantor subsidiaries would have had no aggregate principal amount of obligations outstanding. On December 20, 2012, the RBL Revolver borrowing base was automatically reduced to $1,780.0 million as a result of certain property sales described in “Business—Rockies—Williston Basin.”

 

 

6


Table of Contents

Guarantees

The exchange notes will be fully and unconditionally guaranteed on a senior unsecured basis by each of Samson Resources Company and Samson Investment Company’s existing and future direct or indirect subsidiaries that guarantees obligations under the RBL Revolver and the Second Lien Term Loan or that in the future, guarantees its indebtedness or indebtedness of another guarantor, subject to certain exceptions. Any subsidiary guarantee of the notes will be released in the event such guarantee is released under the RBL Revolver and the Second Lien Term Loan. See “Description of Notes—Guarantees.”

 

Optional Redemption

We may redeem the exchange notes, in whole or in part, at any time prior to February 15, 2016, at a price equal to 100% of the principal amount of the exchange notes redeemed plus accrued and unpaid interest, if any, to the redemption date and a “make-whole premium,” as described under “Description of Notes—Optional Redemption.” Thereafter, we may redeem the notes, in whole or in part, at the redemption prices listed under “Description of Notes—Optional Redemption.”

 

  At any time (which may be more than once) prior to February 15, 2015, we may redeem up to 35% in total of the aggregate principal amount of the exchange notes at a redemption price of 109.750% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, with the net proceeds of certain equity offerings.

 

Change of Control Offer and Certain Asset Sales

Upon the occurrence of a change of control, you will have the right, as holders of the notes, to require us to repurchase some or all of your notes at 101% of their face amount, plus accrued and unpaid interest, if any, to the repurchase date. See “Description of Notes—Repurchase at the Option of Holders—Change of Control.”

 

  If we sell assets under certain circumstances, we will be required to make an offer to purchase the notes at 100% of the principal amount thereof, plus accrued and unpaid interest to the purchase date. See “Description of Notes—Repurchase at the Option of Holders—Asset Sales.”

 

Certain Covenants

The indenture governing the notes contains covenants limiting Samson Investment Company’s ability and the ability of its restricted subsidiaries to, among other things:

 

   

incur additional debt, guarantee debt or issue certain preferred shares;

 

   

pay dividends on or make other distributions in respect of capital stock or make other restricted payments;

 

   

make certain investments;

 

   

sell, transfer or otherwise dispose of certain assets;

 

 

7


Table of Contents
   

create liens on certain assets to secure debt;

 

   

consolidate, merge, sell or otherwise dispose of all or substantially all of its assets;

 

   

enter into certain transactions with affiliates; and

 

   

designate subsidiaries as unrestricted subsidiaries.

 

  These covenants are subject to a number of important qualifications and limitations. See “Description of Notes—Certain Covenants.” During any period in which the exchange notes have investment grade ratings from both Moody’s Investors Service, Inc. (“Moody’s”) and Standard & Poor’s Ratings Services (“S&P”) and no default has occurred and is continuing under the indenture governing the notes, we will not be subject to certain of these covenants.

 

No Prior Market

The exchange notes will be freely transferable but will be new securities for which there will not initially be a market. Accordingly, we cannot assure you whether a market for the exchange notes will develop or as to the liquidity of any such market that may develop.

 

Governing Law

The exchange notes and the related guarantees will be, and the indenture governing the notes is, governed under the laws of the state of New York.

Risk Factors

You should consider carefully all of the information set forth in this prospectus prior to exchanging your outstanding notes. In particular, we urge you to consider carefully the factors set forth under the heading “Risk Factors.”

 

 

8


Table of Contents

Risk Factors

You should carefully consider the risk factors set forth below as well as the other information contained in this prospectus before deciding to tender your outstanding notes in the exchange offer. Any of the following risks may materially and adversely affect our business, results of operations and financial condition. The risks and uncertainties described below are not the only risks and uncertainties that we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also materially and adversely affect our business, results of operations and financial condition. In such a case, you may lose all or part of your original investment. The risks discussed below also include forward-looking statements, and our actual results may differ substantially from those discussed in these forward-looking statements. See “Cautionary Statement Regarding Forward-Looking Statements” in this prospectus.

Risks Relating to the Exchange Offer

There may be adverse consequences if you do not exchange your outstanding notes.

If you do not exchange your outstanding notes for exchange notes in the exchange offer, you will continue to be subject to restrictions on transfer of your outstanding notes as set forth in the offering memorandum distributed in connection with the private placement of the outstanding notes. In general, the outstanding notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the outstanding notes under the Securities Act. You should refer to “Prospectus Summary—The Exchange Offer” and “The Exchange Offer” for information about how to tender your outstanding notes.

The tender of outstanding notes under the exchange offer will reduce the outstanding amount of the outstanding notes, which may have an adverse effect upon, and increase the volatility of, the market prices of the outstanding notes due to a reduction in liquidity.

Your ability to transfer the exchange notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop for the exchange notes.

We do not intend to apply for a listing of the exchange notes on a securities exchange or on any automated dealer quotation system. There is currently no established market for the exchange notes, and we cannot assure you as to the liquidity of markets that may develop for the exchange notes, your ability to sell the exchange notes or the price at which you would be able to sell the exchange notes. If such markets were to exist, the exchange notes could trade at prices that may be lower than their principal amount or purchase price depending on many factors, including prevailing interest rates, the market for similar notes, our financial and operating performance and other factors. An active market for the exchange notes may not develop or, if developed, may not continue. Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the notes. The market, if any, for the exchange notes may experience similar disruptions and any such disruptions may adversely affect the prices at which you may sell your exchange notes.

Certain persons who participate in the Exchange Offer must deliver a prospectus in connection with resales of the exchange notes.

Based on interpretations of the staff of the SEC contained in the Morgan Stanley & Co. Incorporated no action letter (available June 5, 1991) and the Exxon Capital Holdings Corporation no action letter (available May 13, 1988), as interpreted in the Shearman & Sterling no action letter (available July 2, 1993), we believe that you may offer for resale, resell or otherwise transfer the exchange notes without compliance with the registration and prospectus delivery requirements of the Securities Act. However, in some instances described in this prospectus under “Plan of Distribution,” certain holders of exchange notes will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer the exchange notes. If such a

 

9


Table of Contents

holder transfers any exchange notes without delivering a prospectus meeting the requirements of the Securities Act or without an applicable exemption from registration under the Securities Act, such a holder may incur liability under the Securities Act. We do not and will not assume, or indemnify such a holder against this liability.

Risks Relating to the Natural Gas and Oil Industry and Our Business

Natural gas and oil prices are volatile. A decline in natural gas and oil prices could materially adversely affect our business, results of operations, financial condition, access to capital and ability to grow.

Our future business, results of operations, financial condition and rate of growth depend primarily upon the prices we receive for our natural gas and oil production. In addition, the carrying value of our natural gas and oil properties is dependent upon prevailing prices for natural gas and oil. Natural gas and oil prices historically have been volatile, and are likely to continue to be volatile in the future, especially given current economic and geopolitical conditions. Natural gas and oil prices were particularly volatile during 2012. For example, the NYMEX daily settle prices for the front month contract during 2012 ranged from a high of $3.70 to a low of $1.91 per MMBtu for natural gas and a high of $109.77 to a low of $77.69 per Bbl for oil. This price volatility also affects the amount of cash flow we have available for capital expenditures and our ability to borrow money or raise additional capital. The prices for natural gas and oil are subject to a variety of factors beyond our control, such as:

 

   

the domestic and global supply and demand of natural gas (inclusive of natural gas liquids (“NGLs”)) and oil;

 

   

uncertainty in capital and commodities markets;

 

   

the price and quantity of foreign imports;

 

   

global political and economic conditions;

 

   

domestic political and economic conditions;

 

   

political and economic conditions in natural gas and oil producing countries or regions, including the Middle East, Russia, North Sea, Africa and South America;

 

   

the level of consumer product demand;

 

   

weather conditions, force majeure events such as earthquakes and nuclear meltdowns;

 

   

technological advances affecting energy consumption;

 

   

technological advances affecting the development of oil and natural gas reserves;

 

   

domestic and foreign governmental regulations and taxes, including administrative and/or agency actions and policies;

 

   

commodity processing, gathering and transportation cost and availability, and the availability of refining capacity;

 

   

the price and availability of alternative fuels and energy;

 

   

the strengthening and weakening of the U.S dollar relative to other currencies;

 

   

variations between product prices at sales points and applicable index prices;

 

   

hedge fund trading; and

 

   

other speculative activities.

Declines in natural gas and oil prices would not only reduce our revenue, but could reduce the amount of natural gas and oil that we can produce economically and, as a result, could have a material adverse effect on our

 

10


Table of Contents

business, results of operations, financial condition and reserves. If we experience significant price declines, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness (including payments of interest and principal on the notes) or obtain additional capital on attractive terms, all of which could materially adversely affect the value of the notes.

Drilling for and producing natural gas and oil are high risk activities with many uncertainties that could materially adversely affect our business, results of operations and financial condition.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and oil can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenue to return a profit. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, as well as production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, the results of our exploratory drilling in new or emerging areas are more uncertain than drilling results in areas that are developed and have established production. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. Further, many factors may curtail, delay or cancel drilling, including the following:

 

   

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

 

   

delays in receiving governmental permits, orders or approvals;

 

   

pressure or irregularities in geological formations;

 

   

equipment failures or accidents;

 

   

adverse weather conditions;

 

   

declines in natural gas and oil prices;

 

   

surface access restrictions;

 

   

loss of title or other title related issues;

 

   

shortages or delays in the availability of, increases in the cost of, or increased competition for, drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals and supplies;

 

   

limitations in the market for natural gas and oil; and

 

   

restrictions in access to water resources used in drilling and completion operations.

Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages or price increases could significantly decrease our profit margin, cash flow and operating results, or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted or which we may plan in the future.

The occurrence of certain of these events could impact third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries or death or significant property damage. As a result, we face the possibility of liabilities from these events that could materially adversely affect our business, results of operations and financial condition.

In addition, uncertainties associated with enhanced recovery methods may result in our inability to realize an acceptable return on our investments in such projects. The additional production and reserves, if any,

 

11


Table of Contents

attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of natural gas and oil in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. Further, 2-D and 3-D seismic data that we obtain is subject to interpretation and may not accurately identify the presence of natural gas and oil, which could also materially adversely affect the results of our drilling operations.

Estimates of proved reserves and future net cash flows are not precise. The actual quantities of our proved reserves and our future net cash flows may prove to be lower than estimated.

Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. Our estimates of proved reserves and related future net cash flows are based on various assumptions, which may ultimately prove to be inaccurate.

Petroleum engineering and reserve estimation is a subjective process of estimating accumulations of natural gas and/or oil that cannot be measured in an exact manner. Estimates of economically recoverable natural gas and oil reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:

 

   

historical production from the area compared with production from other producing areas;

 

   

the quality, quantity and interpretation of available relevant data;

 

   

the effects of existing, proposed or newly-implemented regulations by governmental agencies;

 

   

operational, drilling and/or completion difficulties;

 

   

future commodity prices;

 

   

future operating costs;

 

   

severance, ad valorem and excise taxes;

 

   

development costs; and

 

   

workover and remedial costs.

Because all reserve estimates are to some degree subjective, each of the following items, or other items not identified below, may differ materially from those assumed in estimating reserves:

 

   

the quantities of natural gas and oil that are ultimately recovered;

 

   

the production and operating costs incurred;

 

   

the amount and timing of future development expenditures; and

 

   

future commodity prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. Our actual production, revenue and expenditures with respect to reserves will likely be different from estimates and the differences may be material.

The estimated discounted future net cash flows from our proved reserves included in this prospectus are based on prices calculated using the unweighted average of the historical first-day-of-the-month natural gas and oil prices for the prior 12 months, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by other factors, including:

 

   

the amount and timing of actual production;

 

   

levels of future capital spending;

 

   

increases or decreases in the supply of, or demand for, natural gas and oil; and

 

   

changes in governmental regulations or taxation.

 

12


Table of Contents

Accordingly, our estimates of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor mandated by the rules and regulations of the SEC to be used in calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our Company or the natural gas and oil industry in general. Therefore, the estimates of our discounted future net cash flows should not be construed as accurate estimates of the current market value of our proved reserves.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate and are dependent upon economically viable commodity prices to justify development. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

Approximately 36% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2012. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of these reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 standard measure value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves, increases in capital expenditures required to develop such reserves and changes in commodity prices could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

Our business requires substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our natural gas and oil reserves and production.

The natural gas and oil industry is capital intensive. For the nine months ended September 30, 2012, we had capital expenditures of $1,090.2 million, including capitalized interest and capitalized internal costs. We have budgeted approximately $758.5 million in capital expenditures for 2013. We expect to continue to make substantial capital expenditures for the development, exploitation, production and acquisition of natural gas and oil reserves. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. We intend to finance our future capital expenditures through cash flows from operations, borrowings under our RBL Revolver, the issuance of debt or equity securities and the sale of assets.

Our cash flow from operations and access to capital are subject to a number of variables, including:

 

   

our proved reserves;

 

   

the level of natural gas and oil we are able to produce from existing wells;

 

   

the prices at which we are able to sell natural gas and oil;

 

   

our ability to acquire, locate and produce new reserves;

 

   

global credit and securities markets; and

 

   

the ability and willingness of lenders and investors to provide capital and the cost of that capital.

If our cash flows or the borrowing base under the RBL Revolver decrease as a result of lower natural gas and oil prices, operating difficulties, declines in reserves or for any other reason, we may be required to seek additional debt or equity financing to sustain our operations at current levels. If we are unable to secure sufficient capital to meet our capital requirements, we may be required to curtail operations, which could lead to a possible decline in our reserves and materially adversely impact our business, results of operations and financial condition.

 

13


Table of Contents

In addition, the costs associated with exploring for, locating and successfully producing oil and natural gas can accumulate very rapidly. If we do not successfully manage the expenses associated with drilling successful oil and natural gas wells, such costs could make the drilling of certain future wells we would ordinarily drill uneconomic.

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential well locations.

Our management has specifically identified drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our business strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: (i) our ability to timely drill wells on lands subject to complex development terms and circumstances; (ii) the availability of capital, equipment, services and personnel; (iii) seasonal conditions; (iv) regulatory and third-party permits, orders and approvals; (v) natural gas and oil prices and (vi) drilling and recompletion costs and results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential drilling locations. Therefore, our actual drilling activities may materially differ from those presently identified, which could materially adversely affect our business, results of operations and financial condition.

We have identified a multi-year inventory of an estimated 4,594 risked drilling locations. As a result of the limitations described above, we may be unable to drill many of our potential well locations. In addition, depending on the timing and concentration of the development of the potential well locations, we would be required to generate or raise significant additional capital to develop all of our potential drilling locations, should we elect to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business, results of operations and financial condition.

Unless we replace our natural gas and oil reserves, our reserves and production will decline, which would materially adversely affect our business, results of operations and financial condition.

Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can also change under other circumstances. As a result, our future natural gas and oil reserves and production and, therefore, our cash flow and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, results of operations and financial condition would be materially adversely affected.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of our growth strategies is to capitalize on opportunistic acquisitions of natural gas and oil reserves. However, our reviews of acquired properties are inherently incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties and will sample the remaining properties for reserve potential. We may also

 

14


Table of Contents

perform only a cursory review of title to properties at the time we acquire interests in them, particularly if we do not intend to drill on the properties immediately. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.

Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for costs, reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

Many of our operations involve utilizing the latest drilling and completion techniques as developed by ourselves and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or natural gas and oil prices decline, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Full cost accounting rules may require us to record certain non-cash asset write-downs in the future, resulting in a material adverse effect on our results of operations.

We utilize the full cost method of accounting for natural gas and oil exploration and development activities. Under full cost accounting, we are required to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of natural gas and oil properties that is equal to the expected after-tax present value (discounted at 10%) of the future net cash flows from proved reserves calculated using the unweighted average of the historical first-day-of-the-month natural gas and oil prices for the prior 12 months. If the net book value of natural gas and oil properties (reduced by any related net deferred income tax liability and asset retirement obligation) exceeds the ceiling limitation, accounting rules require us to impair or “write down” the book value of our natural gas and oil properties. Once incurred, a write-down of natural gas and oil properties is not reversible at a later date.

Costs associated with unevaluated properties are not initially subject to the ceiling test limitation. Rather, we assess all items classified as unevaluated property at least annually for possible impairment or reduction in value based upon our intentions with respect to drilling on such properties, the remaining lease term, geological and geophysical evaluations, drilling results, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. These factors are significantly influenced by current and future commodity prices, development costs, and access to capital at acceptable cost. During any period in which these factors indicate an impairment, the impaired asset value of such property is transferred to the full cost pool and then subject to amortization and the ceiling test limitation. Accordingly, a significant change in these factors,

 

15


Table of Contents

many of which are beyond our control, may shift a significant amount of cost from unevaluated properties into the full cost pool that is subject to amortization and the ceiling test limitation. At September 30, 2012, we had $6,977.9 million of costs associated with unevaluated properties.

As of September 30, 2012, the net capitalized costs of oil and natural gas properties subject to depletion exceeded the ceiling amount and an impairment charge of $569.0 million ($362.4 million net of related deferred income taxes) was recorded. An impairment charge of $39.0 million ($25.2 million net of related deferred income taxes) was recorded during the second quarter of 2012. We could incur additional write-downs in the future, particularly as a result of a decline of natural gas and oil prices, write-offs of costs associated with unevaluated properties or changes in reserve estimates.

We have not yet completed our impairment evaluations for the fourth quarter of 2012. Our annual impairment review of our unevaluated property value is ongoing and we expect to complete our review in March 2013. Consequently, we do not know the amount (if any) of value associated with impaired unevaluated properties that will be transferred to our full cost pool and subject to the ceiling test limitation. In addition, we have not completed other work necessary to estimate or project what (if any) impairment may be recorded as a result of our December 31, 2012 ceiling test.

We have received a third party reserve report prepared as of December 31, 2012, which reflected total proved reserves of $2,760 million using pricing required by the SEC for ceiling test computations. Our proved reserves have decreased by approximately $817.0 million from the amount used in our September 30, 2012 ceiling test. Approximately $660 million of the decline related to our divestiture of properties in the Bakken that occurred in the fourth quarter of 2012. Our full cost pool will be reduced by the difference between the sales proceeds received of approximately $680 million and the carrying value of our unproved property sold, which approximates $181 million. The reduction in the present value of our proved oil and gas reserves resulting from the sale of the Bakken properties exceeds the expected net reduction of our full cost pool. Consequently, the divestitures described above will have a negative impact to our ceiling test calculation for the fourth quarter of 2012. Based on the information summarized above, we believe it is probable that a full cost ceiling impairment will be recorded as a result of our fourth quarter 2012 ceiling test and the impairment expense may be material. For example, if all other inputs to the ceiling test remained constant, the factors described above would result in an additional after tax impairment of approximately $300 million at December 31, 2012.

We may incur substantial losses and be subject to substantial liability claims as a result of our natural gas and oil operations. Additionally we may not be insured for, or our insurance may be inadequate to protect us, against these risks.

Our natural gas and oil exploration and production activities are subject to all of the risks associated with drilling for and producing natural gas and oil, including the possibility of:

 

   

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

 

   

abnormally pressured formations;

 

   

mechanical failures and difficulties, such as stuck oilfield drilling and service tools and casing collapse;

 

   

fires, explosions and ruptures of pipelines;

 

   

fires and explosions at well locations or involving associated equipment;

 

   

personal injuries and death;

 

   

natural disasters; and

 

   

terrorist attacks targeting natural gas and oil related facilities and infrastructure.

 

16


Table of Contents

While we have put in place contingency plans to react to, and deal with, these types of events, it is impossible for us to predict the magnitude of any such event and whether our contingency plans would be sufficient to allow us to successfully respond to such an event in a way that would prevent a material interruption in our business operations.

Any of these risks could materially adversely affect our ability to conduct operations or result in substantial damages and losses to us as a result of:

 

   

injury or loss of life;

 

   

damage to and destruction of property, natural resources and equipment;

 

   

pollution and other environmental damage;

 

   

regulatory investigations and penalties;

 

   

suspension of our operations; and

 

   

repair and remediation costs.

As is common in the natural gas and oil industry, we do not insure fully against all risks associated with our business either because such insurance is not available or because we believe that the premium costs are prohibitive. A loss not fully covered by insurance could have a material adverse effect on our business, results of operations and financial condition. The insurance coverage that we maintain may not be sufficient to cover every claim made against us in the future. A loss in connection with our natural gas and oil operations could have a material adverse effect on our business, results of operation and financial condition to the extent that the insurance coverage provided under our policies is inadequate to cover any such loss.

We have limited control over activities on properties we do not operate, which could reduce our production and revenue or could result in increased liabilities for environmental or safety related incidents.

A significant portion of our business activities is conducted through joint operating, pooling, communitization, unitization or other similar agreements under which we own partial interests in natural gas and oil properties, along with other third parties. If we do not operate such properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of these wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenue. As a result, the success and timing of our drilling and development activities on properties operated by others depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in many of the wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance, which could materially adversely affect our business, results of operations and financial condition.

Cyber attacks targeting systems and infrastructure used by the oil and natural gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. In addition, computer technology controls nearly all of the oil and natural gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber attack directed at oil and natural gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

 

17


Table of Contents

While we have not experienced cyber attacks, we may suffer such losses in the future. Further, as cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber attacks.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

We use independent contractors to provide us with certain technical assistance and services. We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production. We also rely upon the services of other third parties to explore and/or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the activities and business practices of these service providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially adversely affect our business, results of operations and financial condition.

Competition in the natural gas and oil industry is intense, which may materially adversely affect our ability to succeed.

The natural gas and oil industry is intensely competitive, and we compete with other companies that have greater resources, economies of scale or more vertical integration. Many of these companies not only explore for and produce natural gas and oil, but also carry on downstream activities such as refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas leases and mineral estates, productive natural gas and oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of oil and natural gas leases, properties and prospects than our financial or human resources permit. Such competition can also drive up the costs to acquire oil and natural gas leases, properties and prospects in areas where we are already conducting business and operations. In addition, these companies may have a greater ability to continue exploration activities during periods of low commodity prices and/or high service costs. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would materially adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and oil properties.

There is also competition between natural gas and oil producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered or enacted from time to time by the government of the United States or by various state, county, city or other governmental or quasi-governmental entities or agencies where the natural gas and/or oil properties are located. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws, rules and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws, rules and regulations more easily than we can, which would materially adversely affect our competitive position.

Since we were historically a mid-sized, privately-owned company, our company name may not be as well-recognized as some of our larger competitors or some of our similarly-sized competitors who have made greater marketing efforts than we have. This could cause some of our purchasers to purchase products from more well-known companies instead of from us. In addition, our lack of brand identity could limit our exposure to future acquisition and other business opportunities.

 

18


Table of Contents

New technologies may cause our current exploration and drilling methods to become obsolete.

The natural gas and oil industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We may not be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected.

The loss of senior management or other key personnel, who would be difficult to replace, could materially adversely affect operations.

We depend on the performance of our executive officers and other key employees. Our ability to hire and retain our officers and key employees is important to our continued success and growth. The loss of any member of our senior management or other key employees could negatively impact our ability to execute our strategy.

On December 11, 2012, we announced the retirement of our President, Chief Executive Officer and Director, David Adams. We also announced that we were (i) closing our Midland, Texas office, resulting in a severance of all employees located in Midland, Texas and all field or field operations employees assigned to the Permian region and (ii) undertaking an overall reduction in force (the “RIF”) that impacted approximately 10% of our workforce (inclusive of the employees terminated in our Midland office).

As a result of the RIF, we currently estimate that we will record restructuring charges of approximately $47 million, which are expected to be recorded primarily in the fourth quarter of 2012. Our estimated restructuring charges are based on a number of assumptions. Actual results may differ materially from our expectations and additional charges not currently expected may be incurred in connection with, or as a result of, these reductions.

The RIF may be disruptive to our operations. For example, cost saving measures may distract management from our core business, harm our reputation or yield unanticipated consequences, such as attrition beyond the planned reduction in workforce, difficulties in attracting and hiring new employees, increased difficulties in the execution of our day-to-day operations, reduced employee productivity and a deterioration of employee morale. In addition, we may have to rely more on consultants and service providers and incur additional costs to further retain remaining key employees and to hire new employees as an unanticipated consequence of the RIF.

Following the RIF, the term of the change of control agreements for employees who previously had agreements expiring on December 21, 2012 was extended to December 31, 2013. Consequently, a significant percentage of our employees have agreements in place requiring severance payments under certain circumstances if their employment is terminated prior to December 31, 2013.

Moreover, although we believe it is necessary to reduce the cost of our operations to improve our performance, these initiatives may preclude us from making potentially significant expenditures that could improve our competitiveness over the longer term. Such cost reduction measures, or other measures we may take in the future, may not result in the expected cost savings, and any cost savings may be accompanied by these or other unintended consequences.

In addition, our continued drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals who are critical to our business. Despite

 

19


Table of Contents

the recent decline in commodity prices and lower industry activity levels, competition for these professionals remains strong. We are likely to continue to experience increased costs to attract and retain these professionals. Our workforce reductions could also harm our ability to attract such professionals in the future.

Skilled labor shortages and increased labor costs negatively affect our profitability and results of operation.

We may be affected by skilled labor shortages of certain types of technical or qualified personnel, including engineers, geo-professionals, project managers, field supervisors and other technical or qualified personnel, which we have from time-to-time experienced, especially in North American regions where there are large unconventional shale resource plays. These shortages could negatively impact the productivity and profitability of certain projects. Our inability to bid on new and attractive projects, or maintain productivity and profitability on existing projects due to the limited supply of skilled workers and/or increased labor costs could materially adversely affect our profitability and results of operation.

We may be unable to make attractive acquisitions or successfully integrate acquired companies, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of assets or businesses that complement or expand our current business. If we are unable to make these acquisitions because we are: (i) unable to identify attractive acquisition candidates, to analyze acquisition opportunities successfully from an operational and financial point of view or to negotiate acceptable purchase contracts with them; (ii) unable to obtain financing for these acquisitions on economically acceptable terms; or (iii) outbid by competitors, then our future growth could be limited. Furthermore, even if we do make acquisitions they may not result in an increase in our cash flow generated by operations.

Any acquisition involves potential risks, including, among other things:

 

   

mistaken assumptions about volumes, revenues and costs, including synergies;

 

   

difficulties in integrating the operations, technologies, products and personnel of the acquired companies;

 

   

difficulties in complying with regulations, such as environmental regulations, and managing risks related to an acquired business or assets;

 

   

timely completion of necessary financing and required amendments, if any, to existing agreements;

 

   

an inability to implement uniform standards, controls, procedures and policies;

 

   

undiscovered, unknown and unforeseen problems, defects, liabilities or other issues related to any acquisition that become known to us only after the closing of the acquisition;

 

   

limitations on rights to indemnity from the seller;

 

   

mistaken assumptions about the overall costs of equity or debt;

 

   

diversion of management’s and employees’ attention from normal daily operations of the business;

 

   

difficulties in entering regions in which we have no or limited direct prior experience and where competitors in such regions have stronger operating positions; and

 

   

potential loss of key employees, including costly litigation resulting from the termination of those employees.

Any of the above risks could significantly impair our ability to manage our business and materially adversely affect our business, results of operations and financial condition.

 

20


Table of Contents

Our business operations could be disrupted if our information technology systems fail to perform adequately.

The efficient operation of our business depends on our information technology systems. We rely on our information technology systems to effectively manage our business data, communications and other business processes. For example, we are currently implementing a new enterprise resource planning (“ERP”) software system to assist in the management of data across our company. The failure of our information technology systems, including the ERP software system, to perform as we anticipate could disrupt our business and could result in transaction errors, processing inefficiencies, and the loss of sales and customers, causing our business, results of operations and financial condition to suffer. In addition, our information technology systems may be vulnerable to damage or interruption from circumstances beyond our control, including fire, natural disasters, power outages, systems failures, security breaches and viruses. Any such damage or interruption could have a material adverse effect on our business, results of operations and financial condition.

Our costs will increase significantly as a result of becoming an SEC filer and our management will be required to devote substantial time to complying with SEC regulations.

As an SEC filer, we will incur significant legal, accounting and other expenses that we did not incur previously. In addition, the Sarbanes-Oxley Act of 2002 has imposed various requirements, including changes in corporate governance practices, and such requirements will continue to evolve. Our management and other personnel will need to devote a substantial amount of time to comply with these evolving requirements. Moreover, these rules and regulations will increase our legal and financial compliance costs and will make some activities more time-consuming and costly.

In addition, the Sarbanes-Oxley Act of 2002 requires, among other things, that we maintain and periodically evaluate our internal control over financial reporting and disclosure control procedures. In particular, we must perform system and process evaluation and testing of our internal control over financial reporting to allow management to report on the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002. Our compliance with the Sarbanes-Oxley Act of 2002 will require that we incur substantial accounting expense and expend significant management efforts.

Market conditions or operational impediments may hinder our access to natural gas and oil markets or delay our production.

Market or operational conditions or the unavailability of satisfactory natural gas and oil transportation and infrastructure arrangements may hinder our access to natural and oil markets or delay our production. The availability of a ready market for our natural gas and oil production depends on a number of factors, including the demand for and supply of natural gas and oil and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, transportation, fractionation systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially adversely affect our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipelines, gathering system capacity, transportation or processing, treating and fractionation facilities or refinery demand. If that were to occur, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products at a reasonable cost to market.

Our borrowing capacity could be affected by the uncertainty impacting credit markets generally.

Lingering disruptions in the U.S. credit and financial markets and recent international disruptions from the European Union member states unable to service their debt obligations, which have caused investor concerns, could materially adversely affect financial institutions, inhibit lending and limit access to capital and credit for many companies. Although we believe that the banks participating in the RBL Revolver have adequate capital

 

21


Table of Contents

and resources, all of those banks may not continue to operate as a going concern in the future. If any of the banks in our RBL Revolver were to fail, it is possible that the borrowing capacity under our RBL Revolver would be reduced. In the event that the availability under our RBL Revolver were reduced significantly, we could be required to obtain capital from alternate sources in order to finance our capital needs. Our options for addressing such capital constraints would include, but would not be limited to, obtaining commitments from the remaining banks in the lending group or from new banks to fund increased amounts under the terms of our RBL Revolver, and accessing the public capital markets. In addition, we may delay certain capital expenditures to ensure that we maintain appropriate levels of liquidity. If it became necessary to access additional capital, any such alternatives could have terms less favorable than those terms under the RBL Revolver and the Second Lien Term Loan, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

If future financing is not available to us when required, as a result of limited access to the credit markets or otherwise, or is not available to us on acceptable terms, we may be unable to take advantage of business opportunities or respond to competitive pressures, which could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

Our commodity price risk management activities could result in financial losses or could reduce our income.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in commodity prices, we currently enter into derivative arrangements for a portion of our natural gas and oil production and may in the future enter into such arrangements for portions of our natural gas and oil production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative arrangements.

These derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:

 

   

production is less than expected;

 

   

the counterparty to the derivative instrument defaults on its contractual obligations;

 

   

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

 

   

there are issues with regard to legal enforceability of such derivative instruments.

In addition, these types of derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas or oil, and may expose us to cash margin requirements, requiring the posting of cash collateral with counterparties. If we enter into derivative arrangements that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures or make payments on our indebtedness, including the notes.

Our counterparties are typically financial institutions who are lenders under our RBL Revolver. The risk that a counterparty may default on its obligations is heightened by the recent financial sector crisis and other losses incurred by many banks and other financial institutions, including our counterparties or their affiliates. These losses may affect the ability of the counterparties to meet their obligations to us on derivative transactions, which reduce our revenue from derivatives at a time when we are also receiving a lower price for our natural gas and oil sales, that would have otherwise triggered our receipt of the derivative payments. As a result, our business, results of operations and financial condition could be materially adversely affected.

Our commodity price risk management activities could have the effect of reducing our revenue and net income. As of September 30, 2012, the fair value of our hedging contracts was a net liability of $52.7 million. We may continue to incur significant gains or losses in the future from our commodity price risk management activities to the extent market prices increase or decrease and our derivative arrangements remain in place.

 

22


Table of Contents

We are subject to federal, state, local and other laws, regulations and administrative actions and rule making that could increase our costs, reduce our revenues, cash flows or liquidity, or otherwise alter the way we do business.

The exploration, development, production and sale of natural gas and oil in the United States is subject to extensive federal, state, local and other laws, regulations and agency actions, including those pertaining to environmental, health and safety, gathering and transportation of oil and natural gas, conservation policies, reporting obligations and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. We may be required to make large expenditures to comply with applicable governmental rules, regulations, permits or orders. Activities subject to regulation include, but are not limited to:

 

   

the location of wells;

 

   

methods of drilling and completing wells;

 

   

disposal of fluids used and wastes generated in connection with drilling, completion and production operations;

 

   

access to, and surface use and restoration of, surface locations to be used for wells and/or related facilities;

 

   

plugging and abandoning of wells;

 

   

air quality, water quality, wetlands, noise levels and related permits;

 

   

gathering, transportation and marketing of natural gas and oil;

 

   

taxation; and

 

   

access to the water resources used in drilling and completion operations.

In some cases, our operations are subject to federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to state regulations relating to conservation practices and protection of correlative rights. These regulations may affect the timing of our operations, the ability to execute our operations as originally planned and limit the quantity of natural gas and oil we may produce and sell. We generally need to obtain drilling permits from federal, state, local and other governmental authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Failure to comply with such requirements may result in the suspension or termination of operations and subject us to criminal as well as civil and administrative penalties. Compliance costs can be significant. Moreover, the enactment of additional requirements in the future or a change in the interpretation or the enforcement of existing requirements could substantially increase our costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our business, results of operations and financial condition.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety laws and regulations, as well as administrative actions and rule making, applicable to our business.

Our natural gas and oil exploration and production operations are subject to extensive and increasingly stringent federal, state, local and other laws and regulations, as well as administrative actions and rule making, pertaining to the protection of the environment, including those governing the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), the safety of employees, or otherwise relating to pollution or protection

 

23


Table of Contents

of the environment, human health and safety, and natural resources. Wellbore integrity regulations are also being considered by a number of regulatory bodies. We may incur significant costs, delays and liabilities as a result of these requirements. We must take into account the cost of complying with such requirements in planning, designing, constructing, drilling, operating and abandoning wells and related surface facilities, including gathering, transportation, storage and waste disposal facilities. The regulatory frameworks govern, and often require permits for, the handling of drilling and production materials, water withdrawal, disposal of drilling, completion and production wastes, operation of air emissions sources, and drilling activities, including those conducted on lands lying within wilderness, wetlands, Federal and Indian lands and other protected areas. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of our operations. Liabilities, penalties, suspensions, terminations or increased costs resulting from any failure to comply with existing environmental, health or safety requirements, or from the enactment of additional requirements in the future or a change in the interpretation or the enforcement of existing requirements, could materially adversely affect our business, results of operations and financial condition.

There is inherent risk in our operations of incurring significant environmental costs and liabilities due to our generation and handling of petroleum hydrocarbons and wastes, because of our air emissions and wastewater discharges, and as a result of historical industry operations and waste disposal practices. Some of our owned and leased properties have been used for natural gas and oil exploration and production activities for a number of years, often by third parties not under our control. During that time, we and/or other owners and operators of these facilities may have generated or disposed of wastes that allegedly polluted the soil, surface water or groundwater at our facilities and adjacent properties. For our non-operated properties, we are dependent on the operator for operational and regulatory compliance. We could be subject to claims for personal injury, natural resource and property damage (including site clean-up and restoration costs) related to the environmental, health or safety impact of our oil and natural gas production activities, and we have been named from time to time as, and currently are, a defendant in litigation related to such matters. Under certain laws, we also could be subject to joint and several and/or strict liability for the removal or remediation of contamination regardless of whether such contamination was the result of our activities, even if the operations were in compliance with all applicable laws at the time the contamination occurred. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We have been and continue to be responsible for remediating contamination, including at some of our current and former facilities. While to date none of these obligations or claims have involved costs that have materially adversely affected our business, future costs of newly discovered or new contamination may result in a materially adverse impact on our business or operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

While many of our wells are drilled in conventional areas and plays, most of our current operations are in tight and unconventional oil and natural gas formations. Most of these tight and unconventional plays are drilled using hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas and oil production. In recent years the practice has generated and continues to generate controversy at many political levels.

Legislation has been proposed in the U.S. Congress to regulate hydraulic fracturing, including proposals to amend the federal Safe Drinking Water Act to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to

 

24


Table of Contents

initiate legal proceedings based on allegations that specific chemicals used in the fracturing process are impairing groundwater or causing other damage. Such bills, if enacted, could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

In April 2012, the White House issued an executive order creating a multi-agency task force to coordinate federal oversight of hydraulic fracturing. The EPA is undertaking a national study to understand the potential impacts of hydraulic fracturing on drinking water resources. The study will include a review of published literature, analysis of existing data, scenario evaluation and modeling, laboratory studies, and case studies. The EPA issued a progress report in December 2012 detailing the steps being undertaken in the study, and it expects to release a final report for peer review and comment in 2014. The EPA has also announced plans to propose effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities by 2014. In December 2011, the EPA published a draft report finding that hydraulic fracturing is a likely cause of drinking water contamination in the vicinity of Pavillion, Wyoming. While we do not operate wells in the Pavillion gas field, we do have non-operated interests in the field. Findings such as this could increase public pressure on governmental authorities to implement new regulations regarding hydraulic fracturing.

Many states have adopted or are considering similar disclosure legislation and/or other regulations. For example, Texas, Colorado, Utah and Ohio have adopted, and other states such as New York have proposed, new rules regarding hydraulic fracturing, including requiring the disclosure of chemicals injected during hydraulic fracturing. In some areas hydraulic fracturing has also been the subject of local ordinances attempting to ban or limit the practice; court challenges to such ordinances have had varied outcomes to date. If new federal or state laws or regulations are adopted that significantly increase the risk of legal challenges to, or restrict the use of, hydraulic fracturing, such legal requirements could make it more difficult or costly for us to perform hydraulic fracturing and increase our costs of compliance and doing business.

Further, on April 17, 2012, the EPA issued final rules that subject oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAPS”) programs. The EPA proposed rules also include NSPS standards for completion of hydraulically fractured natural gas wells. These standards include the REC techniques developed in the EPA’s Natural Gas STAR program along with pit flaring of natural gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (“MACT”) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently evaluating the effect these rules may have on our business. Final implementation of these rules is expected by 2015.

Based on increased regulation and attention given to the hydraulic fracturing process from federal, state and various local governments, greater opposition and litigation toward oil and natural gas production utilizing hydraulic fracturing techniques is anticipated. Additional legislation or regulation could lead to operational delays or increased operating costs of oil and natural gas wells. Adoption or implementation of regulations regarding hydraulic fracturing could cause a decrease in completion of new oil and natural gas wells all of which could adversely affect our business, financial condition, results of operations and cash flows.

Regulation and agency actions related to climate change and the emission of greenhouse gasses could result in increased operating costs and reduced demand for oil and natural gas and the physical effects of climate change could disrupt our operations.

Global climate change continues to attract considerable public, scientific and regulatory attention, and greenhouse gas (“GHG”) emission regulation is becoming more stringent. The EPA has taken a number of steps towards regulating greenhouse gas emissions under the Clean Air Act, including its Mandatory Reporting of

 

25


Table of Contents

Greenhouse Gases Rule published in October 2009, and expanded in November 2010 to include onshore oil and natural gas production activities, its “endangerment” and “cause or contribute” findings under Section 202(a) of the Clean Air Act published in December 2009, and its so-called “Tailoring Rule” concerning regulation of large emitters of greenhouse gases under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) Program and Title V program issued in May 2010. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” (“BACT”) standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions have been subjected to a number of legal challenges but the U.S. Court of Appeals for the District of Columbia Circuit dismissed these challenges in June 2012. The Supreme Court has not yet decided whether to review this decision. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install BACT for those regulated pollutants that are emitted in certain quantities. Phase I of the Tailoring Rule, which became effective in January 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the Tailoring Rule, which became effective in July 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the Tailoring Rule, which was promulgated in July 2012, excludes smaller sources from the permitting process. Finally, in October 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. The EPA also proposed GHG emissions standards for new power plants in March 2012. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. We are currently required to report annual GHG emissions from some of our operations, and additional GHG emission related requirements that are in various stages of development may also affect our operations. In addition to the EPA initiatives, the U.S. Congress has considered legislation that would establish a nationwide cap-and-trade system for GHGs. If enacted, such laws and regulations could require us to modify existing, or obtain new, permits, implement additional pollution control technology, curtail operations or increase significantly our operating costs.

Regulation of GHG emissions could also result in reduced demand for our products, as oil and natural gas consumers seek to reduce their own GHG emissions. Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could materially adversely affect our business, reputation, operating performance and product demand. In addition, to the extent climate change results in more severe weather and significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other climatic effects, our own or our customers’ operations may be disrupted, which could result in a decrease in our available product or reduce our customers’ demand for products.

The derivatives reform legislation adopted by the U.S. Congress could have a material adverse impact on our ability to hedge risks associated with our business.

The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd Frank”) in 2010. This comprehensive financial reform legislation changes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodity Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. The CFTC recently promulgated regulations to set position limits for certain futures and option

 

26


Table of Contents

contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. Position limits for spot month limits became effective on October 12, 2012 while non-spot month limits for energy-related commodities are not expected to be effective until mid- to late-2013. The CFTC also has proposed regulations to establish minimum capital and margin requirements, as well as clearing and trade-execution requirements in connection with certain derivative activities, although it’s not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under Dodd Frank. In addition, the CFTC’s regulations adopted pursuant to Dodd Frank impose certain recordkeeping and transactional reporting requirements that may be burdensome and costly to us and to the counterparties to our commodity derivative contracts.

The new legislation and any new regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral or provide other credit support, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing commodity derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the new legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, Dodd Frank was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax preferences currently available with respect to natural gas and oil exploration and development are eliminated as a result of future legislation.

The U.S. President’s proposed budget for fiscal 2013 contains a proposal to eliminate certain key U.S. federal income tax preferences currently available to natural gas and oil exploration and production companies. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate certain tax preferences that are currently available with respect to natural gas and oil exploration and development. Any such change could materially adversely impact our business, results of operations and financial condition by increasing the costs we incur which would in turn make it uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938 (the “NGA”) exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”) as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of on-going litigation, so the classification or reclassification and regulation of our gathering facilities are

 

27


Table of Contents

subject to change based on future determinations by FERC, the courts or the U.S. Congress, which could cause our revenue to decline and operating expenses to increase, thereby materially adversely affecting our business, results of operations and financial condition.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Domenici-Barton Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements and possibly requiring the reporting of rates charged for the services provided. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, results of operations and financial condition.

If we fail to maintain effective internal controls over financial reporting at a reasonable assurance level, we may not be able to accurately report our financial results, which could have a material adverse effect on investor confidence, our business and the trading prices of our securities.

We have established internal controls over financial reporting. However, internal controls over financial reporting may not prevent or detect misstatements or omissions because of their inherent limitations, including the possibility of human error, the circumvention or overriding of controls or fraud. Therefore, even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the adequacy of our internal controls, we may be unable to provide financial information in a timely and reliable manner. Any such difficulties or failure may have a material adverse effect on our business, results of operations and financial condition.

In the event we are unable to identify and/or correct deficiencies in our internal controls in a timely manner, we may not be able to record, process, summarize and report financial information accurately and within the time periods required for our financial reporting under the terms of the agreements governing our indebtedness.

On January 24, 2012, we identified a deficiency in our internal controls relating to our accounting for oil and natural gas derivatives as cash flow hedges. Specifically, it was determined that we did not maintain sufficient documentation with the specificity needed to meet hedge accounting requirements under ASC 815, Derivatives and Hedging (“ASC 815”). It was further determined that this deficiency represented a material weakness in our internal control over financial reporting. As a result of this material weakness, we have restated our consolidated financial statements for the fiscal years ended June 30, 2009, 2010 and 2011, included elsewhere in this prospectus.

In connection with the preparation of our financial statements for the transitions period ended December 31, 2012 and for the interim period ended September 30, 2012, we identified certain material weaknesses in the design of our internal controls over financial reporting related to management estimates, manual journal entries, accounting for our oil and gas activities, non-routine transactions and information technology general controls.

We are in the process of remediating the identified control deficiencies. There can be no assurance that we will not identify internal control deficiencies in the future or that control deficiencies will not have a material impact on our financial statements.

Actual and potential litigation could have a material adverse effect on our business, results of operations and financial condition in future periods.

We are subject to claims arising from disputes in the normal course of business with joint owners in our properties, including third-party operators, customers, former and existing employees, vendors and other third

 

28


Table of Contents

parties. These risks may result in lawsuits or other proceedings brought against us or by us. A variety of claims or causes of action have been and may be asserted in lawsuits and proceedings, including, without limitation, contract, tort, common law and equitable claims, and may include multiple plaintiffs or seek certification of a large class of plaintiffs. These risks may be difficult to assess or quantify and their existence and magnitude may remain unknown for substantial periods of time. If the plaintiffs in any suits against us were to successfully prosecute their claims, or if we were to settle such suits by making significant payments to the plaintiffs, our business, results of operations and financial condition would be harmed. Even if the outcome of a claim proves favorable to us, litigation can be time consuming and costly and may divert management resources. While we maintain insurance for our directors and officers, if our senior executives were named in any lawsuit, our indemnification obligations could magnify the costs of these suits.

Affiliates of KKR and the other investors own substantially all of the equity interests in us and may have conflicts of interest with us or the holders of the notes in the future.

As a result of the Acquisition, investment funds affiliated with, and one or more co-investment vehicles controlled by, KKR and the other investors collectively own substantially all of our capital stock, and KKR’s and the other investors’ designees hold substantially all of the seats on our board of directors. As a result, affiliates of KKR and the other investors have control over our decisions to enter into any corporate transaction and have the ability to prevent any transaction that requires the approval of stockholders regardless of whether holders of the notes believe that any such transactions are in their own best interests. For example, affiliates of KKR and the other investors could collectively cause us to make acquisitions that increase the amount of our indebtedness or to sell assets, or could cause us to issue additional capital stock or declare dividends. So long as investment funds affiliated with KKR and the other investors continue to indirectly own a significant amount of the outstanding shares of our capital stock or otherwise control a majority of our board of directors, affiliates of KKR and the other investors will continue to be able to strongly influence or effectively control our decisions. The indenture governing the notes and the credit agreements governing the RBL Facility and the Second Lien Term Loan permit us, under certain circumstances, to pay advisory and other fees, pay dividends and make other restricted payments to KKR and the other investors, and KKR and the other investors or their respective affiliates may have an interest in our doing so.

Additionally, KKR and the other investors are in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us or that supply us with goods and services. KKR and the other investors may also pursue acquisition opportunities that may be complementary to our business and, as a result, those acquisition opportunities may not be available to us. In addition, KKR’s and the other investors’ interests in other portfolio companies could impact our ability to pursue acquisition opportunities. The holders of the notes should consider that the interests of KKR and the other investors may differ from their interests in material respects. See “Security Ownership of Certain Beneficial Owners” and “Certain Relationships and Related Party Transactions.”

Risks Relating to the Exchange Notes

Our substantial indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the notes.

We have a significant amount of indebtedness. As of September 30, 2012, we had total indebtedness of $4.265 billion (excluding our redeemable preferred stock) and availability under the RBL Revolver of approximately $984 million (before giving effect to $1.1 million of outstanding letters of credit, which reduce availability). For more information about our RBL Revolver, see “Description of Other Indebtedness—RBL Revolver “ and “Description of Other Indebtedness—Second Lien Term Loan.”

 

29


Table of Contents

Specifically, our high level of indebtedness could have important consequences to the holders of the notes, including:

 

   

making it more difficult for us to satisfy our obligations with respect to the notes and our other indebtedness;

 

   

limiting our ability to obtain additional financing to fund future working capital, capital expenditures, investments or acquisitions or other general corporate requirements;

 

   

requiring a substantial portion of our cash flows to be dedicated to debt service payments instead of other purposes, thereby reducing the amount of cash flows available for working capital, capital expenditures, investments or acquisitions and other general corporate purposes;

 

   

increasing our vulnerability to adverse changes in general economic, industry and competitive conditions;

 

   

exposing us to the risk of increased interest rates as certain of our borrowings, including borrowings under the RBL Revolver, are at variable rates of interest;

 

   

reducing our ability to borrow additional funds if we do not replace our reserves since our borrowing base is automatically redetermined based on the value of our proved reserves;

 

   

limiting our ability to fund future capital expenditures and working capital, engaging in future acquisitions or development activities, or otherwise realizing the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;

 

   

restricting us from making strategic acquisitions or causing us to make non-strategic divestitures;

 

   

preventing us from raising the funds necessary to repurchase all notes tendered to us upon the occurrence of certain changes of control, which failure to repurchase would constitute a default under the indenture governing the notes;

 

   

limiting our flexibility in planning for, or reacting to, changes in our business or industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploring;

 

   

impairing our ability to obtain additional financing in the future;

 

   

placing us at a disadvantage compared to other, less leveraged competitors;

 

   

exposing us to greater financial exposures because the notes are high yield investments; and

 

   

increasing our cost of borrowing.

In addition, the credit agreements governing the RBL Revolver and the Second Lien Term Loan contain, and the indenture governing the notes contains, restrictive covenants that limit our ability to engage in activities that may be in our long-term best interest. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of substantially all of our indebtedness.

We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments on, or refinance our debt obligations, including the notes, depends on our financial condition and operating performance, which are subject to prevailing economic, industry and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond our control (including the factors discussed under “—Risks Relating to the Natural Gas and Oil Industry and Our Business” above). We may be unable to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the notes.

 

30


Table of Contents

If our cash flow and capital resources are insufficient to fund our debt service obligations, we could face substantial liquidity problems and could be forced to reduce or delay investments and capital expenditures or to dispose of material assets or operations, seek additional debt or equity capital or restructure or refinance our indebtedness, including the notes. We may not be able to effect any such alternative measures on commercially reasonable terms or at all and, even if successful, those alternative actions may not allow us to meet our scheduled debt service obligations. The credit agreements governing the RBL Revolver and the Second Lien Term Loan restrict, and the indenture governing the notes restricts, our ability to dispose of assets and use the proceeds from those dispositions and may also restrict our ability to raise debt or equity capital to be used to repay other indebtedness when it becomes due. We may not be able to consummate those dispositions or to obtain proceeds in an amount sufficient to meet any debt service obligations then due.

In addition, we derive substantially all of our operating income and cash flow from our subsidiaries, certain of which are not guarantors of the notes or our other indebtedness. Accordingly, repayment of our indebtedness, including the notes, is dependent on the generation of cash flow by our subsidiaries and their ability to make such cash available to us, by dividend, debt repayment or otherwise. Unless they are guarantors of the notes or our other indebtedness, our subsidiaries do not have any obligation to pay amounts due on the notes or our other indebtedness or to make funds available for that purpose. Our subsidiaries may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect of our indebtedness, including the notes. Each subsidiary is a distinct legal entity, and, under certain circumstances, legal, practical and contractual restrictions may limit our ability to obtain cash from our subsidiaries.

While the indenture governing the notes and the credit agreements governing the RBL Revolver and the Second Lien Term Loan limit the ability of our restricted subsidiaries to incur consensual restrictions on their ability to pay dividends or make other intercompany payments to us, these limitations are subject to qualifications and exceptions. In the event that we do not receive distributions from our subsidiaries, we may be unable to make required principal and interest payments on our indebtedness, including the notes.

Our inability to generate sufficient cash flow to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms, or at all, would materially adversely affect our business, results of operations and financial condition and our ability to satisfy our obligations under the notes.

If we cannot make scheduled payments on our indebtedness, we will be in default and holders of the notes could declare all outstanding principal and interest to be due and payable, the lenders under the RBL Revolver could terminate their commitments to loan money, our secured lenders (including the lenders under the RBL Revolver and the Second Lien Term Loan) could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation. All of these events could result in you losing your entire investment in the notes.

Despite our level of indebtedness, we and our subsidiaries may still be able to incur substantially more indebtedness. This could further exacerbate the risks to our financial condition described above and prevent us from fulfilling our obligations under the notes.

We and our subsidiaries may be able to incur significant additional indebtedness in the future. Although the credit agreements governing the RBL Revolver and the Second Lien Term Loan and the indenture governing the notes contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and the additional indebtedness incurred in compliance with these restrictions could be substantial. If we incur any additional indebtedness that ranks equally with the notes, the holders of that indebtedness will be entitled to share ratably with you in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding up of our Company, subject to collateral arrangements. This may have the effect of reducing the amount of proceeds paid to you. These restrictions also will not prevent us from incurring obligations that do not constitute indebtedness.

 

31


Table of Contents

Any increase in our level of indebtedness will have several important effects on our future operations, including, without limitation:

 

   

we will have additional cash requirements in order to support the payment of interest on our outstanding indebtedness;

 

   

increases in our outstanding indebtedness and leverage will increase our vulnerability to adverse changes in general economic and industry conditions, and could put us at a competitive disadvantage against other less leveraged competitors that have more cash flow to devote to their businesses;

 

   

depending on the levels of our outstanding indebtedness, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be limited; and

 

   

our level of indebtedness may limit our flexibility in operating our business and prevent us from engaging in certain transactions that might otherwise be beneficial to us.

All of the borrowings under the RBL Revolver and the Second Lien Term Loan are secured indebtedness and therefore are effectively senior to the notes and the guarantees of the notes by the guarantors to the extent of the value of the assets securing such indebtedness. If new indebtedness is added to our current indebtedness levels, the related risks that we and the guarantors now face could intensify. See “Description of Other Indebtedness” and “Description of Notes.”

The terms of the credit agreements governing the RBL Revolver and the Second Lien Term Loan and the indenture governing the notes restrict our current and future operations.

The credit agreements governing the RBL Revolver and the Second Lien Term Loan and the indenture governing the notes contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our best interest, including restrictions on our ability to:

 

   

incur additional indebtedness, guarantee indebtedness or issue certain preferred shares;

 

   

pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock;

 

   

prepay, redeem or repurchase certain debt;

 

   

make loans, investments and other restricted payments;

 

   

sell, transfer or otherwise dispose of certain assets;

 

   

create or incur liens;

 

   

enter into transactions with affiliates;

 

   

alter the businesses we conduct;

 

   

enter into agreements restricting our subsidiaries’ ability to pay dividends; and

 

   

consolidate, merge or sell all or substantially all of our assets.

The covenants in the indenture governing the notes are subject to important exceptions and qualifications, which are described under “Description of Notes.” Certain of these covenants will cease to apply to the notes at all times when the notes have investment grade ratings from both Moody’s and S&P. See “Description of Notes—Certain Covenants—Effectiveness of Covenants.”

A breach of the covenants under the credit agreements governing the RBL Revolver and the Second Lien Term Loan or the indenture governing the notes could result in an event of default under the applicable indebtedness. Such a default may allow the creditors to accelerate the related indebtedness and may result in the acceleration of any other indebtedness to which a cross-acceleration or cross-default provision applies. In

 

32


Table of Contents

addition, an event of default under the credit agreements governing the RBL Revolver and the Second Lien Term Loan would permit the lenders under the RBL Revolver to terminate all commitments to extend further credit under that facility. Furthermore, if we were unable to repay the amounts due and payable under the RBL Revolver and the Second Lien Term Loan, those lenders could proceed against the collateral granted to them to secure that indebtedness. In the event our lenders or noteholders accelerate the repayment of our borrowings, we may not have sufficient assets to repay that indebtedness.

The restrictions contained in the credit agreements governing the RBL Revolver and the Second Lien Term Loan and the indenture governing the notes could materially adversely affect our ability to:

 

   

finance our operations;

 

   

make needed capital expenditures;

 

   

make strategic acquisitions or investments or enter into joint ventures;

 

   

withstand a future downturn in our business, the industry or the economy in general;

 

   

engage in business activities, including future opportunities, that may be in our interest; and

 

   

plan for or react to market conditions or otherwise execute our business strategies.

These restrictions, among other things, may affect our ability to grow.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under the RBL Revolver and the Second Lien Term Loan are at variable rates of interest and expose us to interest rate risk. Assuming all revolving loans are fully drawn, each quarter point change in interest rates would result in a $7.5 million change in annual interest expense on indebtedness under the RBL Revolver and the Second Lien Term Loan. In the future, we may enter into interest rate swaps that involve the exchange of floating for fixed rate interest payments in order to reduce interest rate volatility. However, we may not maintain interest rate swaps with respect to all of our variable rate indebtedness, and any swaps we enter into may not fully mitigate our interest rate risk, may prove disadvantageous or may create additional risks, including risks discussed in “—Risks Relating to the Natural Gas and Oil Industry and Our Business” above.

If the financial institutions that are part of the syndicate of the RBL Revolver fail to extend credit under that facility, our liquidity and results of operations may be materially adversely affected.

We expect to have access to capital through the RBL Revolver. Each financial institution which is part of the syndicate for the RBL Revolver will be responsible, on a several, but not joint, basis, for providing a portion of the loans to be made under that facility. If any participant or group of participants with a significant portion of the commitments in the RBL Revolver fail to satisfy its or their respective obligations to extend credit under the facility, and we are unable to find a replacement for such participant or participants on a timely basis (if at all), our liquidity and results of operations may be materially adversely affected.

The notes are effectively subordinated to Samson Investment Company’s and the guarantors’ indebtedness under the RBL Revolver and the Second Lien Term Loan and any other future secured indebtedness of Samson Investment Company and the guarantors to the extent of the value of the assets securing such indebtedness.

The notes are not secured by any of Samson Investment Company’s or the guarantors’ assets. As a result, the notes and the guarantees are effectively subordinated to Samson Investment Company’s and the guarantors’ indebtedness under the RBL Revolver and the Second Lien Term Loan with respect to the assets that secure such indebtedness. As of September 30, 2012 we had availability under the RBL Revolver of approximately

 

33


Table of Contents

$984 million (before giving effect to $1.1 million of outstanding letters of credit, which reduce availability), and Samson Investment Company and the guarantors had $1.015 billion of secured debt outstanding under the RBL Revolver and $1 billion of secured debt outstanding under the Second Lien Term Loan. In addition, we may incur additional secured debt in the future. The effect of this subordination is that upon a default in payment on, or the acceleration of, any of our secured indebtedness, or in the event of bankruptcy, insolvency, liquidation, dissolution or reorganization of Samson Investment Company or the guarantors of the RBL Revolver and the Second Lien Term Loan or of other secured debt, the proceeds from the sale of assets securing our secured indebtedness will be available to pay obligations on the notes only after all indebtedness under the RBL Revolver and the Second Lien Term Loan and the other secured debt has been paid in full. As a result, the holders of the notes may receive less, ratably, than the holders of secured debt in the event of Samson Investment Company’s or the guarantors’ bankruptcy, insolvency, liquidation, dissolution or reorganization.

The notes are structurally subordinated to all obligations of Samson Investment Company’s existing and future subsidiaries that are not and do not become guarantors of the notes.

The notes are guaranteed by each of Samson Investment Company’s existing and subsequently acquired or organized subsidiaries (other than the issuer of the notes) that are borrowers under or guarantee the RBL Revolver and the Second Lien Term Loan or that, in the future, guarantee Samson Investment Company’s indebtedness or indebtedness of another guarantor, subject to certain exceptions. Samson Investment Company’s subsidiaries that do not guarantee the notes have no obligation, contingent or otherwise, to pay amounts due under the notes or to make any funds available to pay those amounts, whether by dividend, distribution, loan or other payment. The notes are structurally subordinated to all indebtedness and other obligations of any non-guarantor subsidiary such that in the event of insolvency, liquidation, reorganization, dissolution or other winding up of any subsidiary that is not a guarantor, all of that subsidiary’s creditors (including trade creditors and preferred stockholders, if any) would be entitled to payment in full out of that subsidiary’s assets before we would be entitled to any payment.

In addition, the indenture governing the notes, subject to some limitations, permits these subsidiaries to incur additional indebtedness and does not contain any limitation on the amount of other liabilities, such as trade payables, that may be incurred by these subsidiaries.

In addition, Samson Investment Company’s subsidiaries that provide, or will provide, guarantees of the notes will be automatically released from those guarantees upon the occurrence of certain events, including the following:

 

   

the designation of that subsidiary guarantor as an unrestricted subsidiary;

 

   

the release or discharge of any guarantee or indebtedness that resulted in the creation of the guarantee of the notes by such guarantor; or

 

   

the sale or other disposition, including the sale of substantially all the assets, of that subsidiary guarantor.

If any subsidiary guarantee is released, no holder of the notes will have a claim as a creditor against that subsidiary, and the indebtedness and other liabilities, including trade payables and preferred stock, if any, whether secured or unsecured, of that subsidiary will be structurally senior to the claim of any holders of the notes. See “Description of Notes—Guarantees.”

The lenders under the RBL Revolver will have the discretion to release any guarantors under the RBL Revolver in a variety of circumstances, which will cause those guarantors to be released from their guarantees of the notes.

While any obligations under the RBL Revolver remain outstanding, any guarantee of the notes may be released without action by, or consent of, any holder of the notes or the trustee under the indenture governing the

 

34


Table of Contents

notes, at the discretion of lenders under the RBL Revolver, if the related guarantor is no longer a guarantor of obligations under the RBL Revolver or any other indebtedness. See “Description of Notes.” The lenders under the RBL Revolver will have the discretion to release the guarantees under the RBL Revolver in a variety of circumstances. You will not have a claim as a creditor against any entity that is no longer a guarantor of the notes, and the indebtedness and other liabilities, including trade payables, whether secured or unsecured, of those subsidiaries will effectively be senior to claims of noteholders.

If we default on our obligations to pay our other indebtedness, we may not be able to make payments on the notes.

Any default under the agreements governing our indebtedness, including a default under the RBL Revolver and the Second Lien Term Loan that is not waived by the required lenders, and the remedies sought by the holders of such indebtedness, could prevent us from paying principal, premium, if any, and interest on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants in the instruments governing our indebtedness (including certain covenants in the RBL Revolver and the Second Lien Term Loan and the indenture governing the notes), we could be in default under the terms of the agreements governing such indebtedness, including the RBL Revolver and the Second Lien Term Loan and the indenture governing the notes. In the event of such default:

 

   

the holders of such indebtedness may be able to cause all of our available cash flow to be used to pay such indebtedness and, in any event, could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest;

 

   

the lenders under the RBL Revolver, together with the lenders under the Second Lien Term Loan, could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and

 

   

we could be forced into bankruptcy or liquidation.

Upon any such bankruptcy filing, we would be stayed from making any ongoing payments on the notes, and the holders of the notes would not be entitled to receive post-petition interest or applicable fees, costs or charges, or any “adequate protection” under Title 11 of the U.S. Bankruptcy Code (the “Bankruptcy Code”). Furthermore, if a bankruptcy case were to be commenced under the Bankruptcy Code, we could be subject to claims, with respect to any payments made within 90 days prior to commencement of such a case, that we were insolvent at the time any such payments were made and that all or a portion of such payments, which could include repayments of amounts due under the notes, might be deemed to constitute a preference, under the Bankruptcy Code, and that such payments should be voided by the bankruptcy court and recovered from the recipients for the benefit of the entire bankruptcy estate. Also, in the event that we were to become a debtor in a bankruptcy case seeking reorganization or other relief under the Bankruptcy Code, a delay and/or substantial reduction in payment under the notes may otherwise occur.

If our operating performance declines, we may in the future need to obtain waivers from the required lenders under the RBL Revolver and the Second Lien Term Loan to avoid being in default. If we breach our covenants under the RBL Revolver or the Second Lien Term Loan and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under the RBL Revolver and the Second Lien Term Loan, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.

We may not be able to repurchase the notes upon a change of control.

Upon the occurrence of certain change of control events, we will be required to offer to repurchase all or any part of the notes then outstanding at 101% of their principal amount, plus accrued and unpaid interest, if any,

 

35


Table of Contents

to the purchase date. Additionally, under the RBL Revolver and the Second Lien Term Loan, a change of control (as defined therein) constitutes an event of default that permits the lenders to accelerate the maturity of borrowings and terminate their commitments to lend. The source of funds for any purchase of the notes and repayment of borrowings under the RBL Revolver and the Second Lien Term Loan would be our available cash or cash generated from our subsidiaries’ operations or other sources, including borrowings, sales of assets or sales of equity. We may not be able to repurchase the notes upon a change of control because we may not have sufficient financial resources to purchase all of the debt securities that are tendered upon a change of control and repay our other indebtedness that will become due. We may require additional financing from third parties to fund any such purchases, and we may be unable to obtain financing on satisfactory terms or at all. Further, our ability to repurchase the notes may be limited by law. In order to avoid the obligations to repurchase the notes and events of default and potential breaches of the credit agreements governing the RBL Revolver and the Second Lien Term Loan, we may have to avoid certain change of control transactions that would otherwise be beneficial to us.

In addition, some important corporate events, such as leveraged recapitalizations, may not, under the indenture governing the notes, constitute a “change of control” that would require Samson to repurchase the notes, even though those corporate events could increase the level of our indebtedness or otherwise adversely affect our capital structure, credit ratings, financial condition or the value of the notes. See “Description of Notes—Repurchase at the Option of Holders—Change of Control.”

We may enter into transactions that would not constitute a change of control that could affect our ability to satisfy our obligations under the notes.

Legal uncertainty regarding what constitutes a change of control and the provisions of the indenture governing the notes may allow us to enter into transactions, such as acquisitions, refinancing or recapitalizations, that would not constitute a change of control but may increase our outstanding indebtedness or otherwise affect our ability to satisfy our obligations under the notes. The definition of change of control for purposes of the notes includes a phrase relating to the transfer of “all or substantially all” of our assets taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, your ability to require us to repurchase notes as a result of a transfer of less than all of our assets to another person may be uncertain. Although overturned on other grounds, a Florida bankruptcy court found that this kind of provision was not effective to protect guarantees.

U.S. federal and state fraudulent transfer laws may permit a court to void the notes and/or the guarantees, and if that occurs, you may not receive any payments on the notes.

U.S. federal and state fraudulent transfer and conveyance statutes may apply to the issuance of the notes and the incurrence of the guarantees of the notes. Under U.S. federal bankruptcy law and comparable provisions of state fraudulent transfer or conveyance laws, which may vary from state to state, the notes or the guarantees thereof could be voided as a fraudulent transfer or conveyance if Samson Investment Company or any of the guarantors, as applicable, (a) issued the notes or incurred the guarantees with the intent of hindering, delaying or defrauding creditors or (b) received less than reasonably equivalent value or fair consideration in return for either issuing the notes or incurring the guarantees and, in the case of (b) only, one of the following is also true at the time thereof:

 

   

Samson Investment Company or any of the guarantors, as applicable, were insolvent or rendered insolvent by reason of the issuance of the notes or the incurrence of the guarantees;

 

   

the issuance of the notes or the incurrence of the guarantees left Samson Investment Company or any of the guarantors, as applicable, with an unreasonably small amount of capital or assets to carry on the business;

 

   

Samson Investment Company or any of the guarantors intended to, or believed that Samson Investment Company or such guarantor would, incur debts beyond Samson Investment Company’s or the guarantor’s ability to pay as they mature; or

 

36


Table of Contents
   

Samson Investment Company or any of the guarantors were a defendant in an action for money damages, or had a judgment for money damages docketed against Samson or the guarantor if, in either case, the judgment is unsatisfied after final judgment.

As a general matter, value is given for a transfer or an obligation if, in exchange for the transfer or obligation, property is transferred or a valid antecedent debt is secured or satisfied. A debtor will generally not be considered to have received value in connection with a debt offering if the debtor uses the proceeds of that offering to make a dividend payment or otherwise retire or redeem equity securities issued by the debtor. A court would likely find that a subsidiary guarantor did not receive reasonably equivalent value or fair consideration for its guarantee to the extent the guarantor did not obtain a reasonably equivalent benefit directly or indirectly from the issuance of the notes.

We cannot be certain as to the standards a court would use to determine whether or not Samson Investment Company or the guarantors were insolvent at the relevant time or, regardless of the standard that a court uses, whether the notes or the guarantees would be subordinated to Samson Investment Company’s or any of the guarantors’ other debt. In general, however, a court would deem an entity insolvent if:

 

   

the sum of its debts, including contingent and unliquidated liabilities, was greater than the fair saleable value of all of its assets;

 

   

the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

 

   

it could not pay its debts as they became due.

If a court were to find that the issuance of the notes or the incurrence of a guarantee was a fraudulent transfer or conveyance, the court could void the payment obligations under the notes or that guarantee, could subordinate the notes or that guarantee to presently existing and future indebtedness of Samson Investment Company or of the related guarantor or could require the holders of the notes to repay any amounts received with respect to that guarantee. In the event of a finding that a fraudulent transfer or conveyance occurred, you may not receive any repayment on the notes. Further, the avoidance of the notes could result in an event of default with respect to our and our subsidiaries’ other debt that could result in acceleration of that debt.

If the guarantees were legally challenged, any guarantee could also be subject to the claim that, since the guarantee was incurred for Samson Investment Company’s benefit, and only indirectly for the benefit of the applicable guarantor, the obligations of the applicable guarantor were incurred for less than fair consideration. A court could thus void the obligations under the guarantees, subordinate them to the applicable guarantor’s other debt or take other action detrimental to the holders of the notes.

Although each guarantee entered into by a guarantor will contain a provision intended to limit that guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent transfer, this provision may not be effective to protect those guarantees from being voided under fraudulent transfer law, or may reduce that guarantor’s obligation to an amount that effectively makes its guarantee worthless.

In addition, any payment by Samson Investment Company pursuant to the notes made at a time that Samson was found to be insolvent could be voided and required to be returned to Samson Investment Company or to a fund for the benefit of Samson Investment Company’s creditors if such payment is made to an insider within a one-year period prior to a bankruptcy filing or within 90 days for any outside party and such payment would give such insider or outsider party more than such creditors would have received in a distribution under the Bankruptcy Code.

 

37


Table of Contents

Finally, as a court of equity, the bankruptcy court may subordinate the claims in respect of the notes to other claims against Samson Investment Company under the principle of equitable subordination if the court determines that (1) the holder of notes engaged in some type of inequitable conduct, (2) the inequitable conduct resulted in injury to our other creditors or conferred an unfair advantage upon the holders of notes and (3) equitable subordination is not inconsistent with the provisions of the Bankruptcy Code.

Many of the restrictive covenants contained in the indenture governing the notes will not apply during any period in which the notes are rated investment grade by both Moody’s and S&P.

Many of the covenants contained in the indenture governing the notes will not apply to us during any period in which the notes are rated investment grade by both Moody’s and S&P’s, provided at such time no default or event of default has occurred and is continuing. Such covenants will restrict, among other things, our ability to make certain distributions, incur indebtedness and enter into certain other transactions. There can be no assurance that the notes will ever be rated investment grade, or that if they are rated investment grade, that the notes will maintain these ratings. However, suspension of these covenants would allow us to engage in certain transactions that would not be permitted while these covenants were in force. To the extent the covenants are subsequently reinstated, any such actions taken while the covenants were suspended would not result in an event of default under the indenture governing the notes. See “Description of Notes—Certain Covenants—Effectiveness of Covenants.”

 

38


Table of Contents

Cautionary Statement Regarding Forward-Looking Statements

This prospectus contains forward-looking statements, which reflect our expectations regarding our future growth, results of operations, operational and financial performance, business prospects and opportunities and future events. Words such as, but not limited to, “anticipate,” “continue,” “estimate,” “expect,” “may,” “might,” “will,” “project,” “should,” “believe,” “intend,” “continue,” “could,” “plan,” “predict” and negatives of these words and similar expressions are intended to identify forward-looking statements. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this prospectus are forward-looking statements. These statements are based on, but not limited to, management’s assessment of such factors as the condition of our industry and the competitive environment. These assessments could prove inaccurate.

All forward-looking statements involve risks and uncertainties. The occurrence of the events described and the achievement of the expected results depend on many events, some or all of which are not predictable or within our control. Although the forward-looking statements contained in this prospectus reflect our current beliefs based upon information currently available to us and upon assumptions which we believe to be reasonable, actual results may differ materially from expected results.

Factors that may cause actual results to differ from expected results include, among others:

 

   

fluctuations in natural gas and oil prices;

 

   

uncertainties relating to the drilling of our wells;

 

   

estimates of our reserves, future net revenues and PV-10;

 

   

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

 

   

our financial strategy, liquidity and capital required for our development program;

 

   

changes in the availability and cost of capital;

 

   

proved and unproved drilling locations and future drilling plans;

 

   

production rates relating to our natural gas and oil reserves;

 

   

our ability to capitalize on opportunistic acquisitions of natural gas and oil reserves;

 

   

write-downs and decline in value of undeveloped acreage if drilling results are unsuccessful;

 

   

recording of certain non-cash asset write-downs in the future;

 

   

liability claims as a result of our natural gas and oil operations;

 

   

actions taken or non-performance by third parties, including other working interest owners, contractors, operators, processors, transporters and customers;

 

   

competitive conditions in our industry;

 

   

the use and development of new industry technologies;

 

   

our ability to recruit and retain qualified personnel necessary to operate our business;

 

   

our ability to consummate and successfully integrate acquisitions and our ability to realize any cost savings and other synergies from any acquisition;

 

   

the performance of our information technology systems;

 

   

general economic and business conditions;

 

   

our hedging strategy and results;

 

39


Table of Contents
   

the effects of existing and future laws and governmental regulations, including environmental, hydraulic fracturing and climate change regulation;

 

   

the effects of derivatives reform legislation;

 

   

elimination of certain natural gas and oil exploration and development federal and state tax deductions and credits;

 

   

compliance with existing and future FERC regulation;

 

   

the effects of existing or future litigation; and

 

   

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

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the caption “Risk Factors” in this prospectus.

Reserve engineering is a process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

 

40


Table of Contents

Use of Proceeds

We will not receive any cash proceeds from the issuance of the exchange notes pursuant to the exchange offer. In consideration for issuing the exchange notes as contemplated in this prospectus, we will receive in exchange a like principal amount of outstanding notes, the terms of which are identical in all material respects to the exchange notes, except that the exchange notes will not contain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement. The outstanding notes surrendered in exchange for the exchange notes will be retired and cancelled and cannot be reissued. Accordingly, the issuance of the exchange notes will not result in any change in our capitalization.

 

41


Table of Contents

Capitalization

The following table summarizes the cash position and capitalization of Samson Resources Corporation as of September 30, 2012 (i) on an actual basis and (ii) on an as adjusted basis after giving effect to the divestiture of certain assets in the Williston Basin in December 2012 for total proceeds of $650.0 million as described in our unaudited pro forma condensed consolidated financial statements, included elsewhere in this prospectus. The proceeds were used to pay down amounts outstanding on the RBL Revolver.

This table is presented and should be read in conjunction with our consolidated financial statements, together with the related notes thereto, included elsewhere in this prospectus. Also see “Selected Historical Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Description of Other Indebtedness.”

 

     As of September 30, 2012  
     Actual     As Adjusted  
    

(in millions)

(unaudited)

(as restated and recast)

 

Cash and cash equivalents

   $ 112.8      $ 112.8   
  

 

 

   

 

 

 

Debt:

    

RBL Revolver(1)

     1,015.0        365.0   

Second Lien Term Loan

     1,000.0        1,000.0   

9.750% Senior Notes due 2020

     2,250.0        2,250.0   

Preferred Stock(2)

     171.4        171.4   

Total debt

     4,436.4        3,786.4   

Common stock

     8.3        8.3   

Paid-in capital

     4,160.9        4,160.9   

Accumulated deficit

     (476.1     (476.1

Accumulated other comprehensive loss

     (10.0     (10.0

Total shareholders’ equity(3)

     3,683.1        3,683.1   
  

 

 

   

 

 

 

Total capitalization

   $ 8,119.5      $ 7,469.5   
  

 

 

   

 

 

 

 

(1) At September 30, 2012, our RBL Revolver provided for revolving credit financings of up to $2,000.0 million. As of September 30, 2012, we had availability under the RBL Revolver of approximately $984 million (before giving effect to $1.1 million of outstanding letters of credit, which reduce availability). On December 20, 2012, the RBL Revolver borrowing base was reduced to $1,780.0 million as a result of certain property sales described in “Business—Rockies—Williston Basin”, as provided for in our credit agreement. For more information about our RBL Revolver see “Description of Other Indebtedness—RBL Revolver.”
(2) Represents the book value of cumulative preferred stock with an aggregate liquidation preference of $182.8 million. For more information about the cumulative preferred stock see “Description of Other Indebtedness—Cumulative Preferred Stock.”
(3) Excludes puttable common stock with a book value of $12.4 million at September 30, 2012.

 

42


Table of Contents

Ratio of Earnings to Fixed Charges

The following table sets forth our ratio of earnings to fixed charges for the periods presented:

 

    2007     2008     2009      2010     2011     July 1,
2011
through
December 21,
2011
    From
Inception
(November
14, 2011)
through
December 31,
2011
    Nine
Months
Ended
September 30,
2012
 

Ratio of earnings to fixed
charges(1)

    22.7x        5.5x        —(2)         8.7x        4.4x        (2)      (2)      (2) 

 

(1) For the purposes of computing the ratio of earnings to fixed charges, “earnings” consists of net income (loss) from continuing operations before income taxes plus fixed charges. “Fixed charges” represents interest incurred, amortization of deferred debt costs and that portion of rental expense on operating leases deemed to be the equivalent of interest.
(2) Due to our operating losses for the year ended June 30, 2009, the period from July 1, 2011 through December 21, 2011, the period from inception (November 14, 2011) through December 31, 2011 and the nine months ended September 30, 2012, the respective ratios of coverage were less than 1:1. To achieve ratio coverage of 1:1, we would have needed additional earnings of approximately $888.8 million, $231.1 million, $121.8 million, and $841.9 million, respectively.

 

43


Table of Contents

Selected Historical Consolidated Financial Data

The selected historical consolidated financial data of Samson Resources Corporation for the period from inception (November 14, 2011) through December 31, 2011, and the consolidated financial statements of the Predecessor for the period from July 1, 2011 through December 21, 2011 and for the fiscal years ended June 30, 2011, 2010, 2009, 2008 and 2007 is presented in the table below. The balance sheet data and statement of income (loss) and comprehensive income (loss) as of and for the Successor period ended December 31, 2011 and for the Predecessor period ended December 21, 2011, and as of and for the years ended June 30, 2011, 2010 and 2009 are derived from our audited consolidated financial statements included elsewhere in this prospectus. The selected consolidated financial data for the nine months ended September 30, 2011 and 2012 and as of September 30, 2012 has been derived from our unaudited consolidated financial statements included elsewhere in this prospectus. The unaudited consolidated financial statements have been prepared on a basis consistent with our audited consolidated financial statements and include, in the opinion of management, all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of such consolidated financial data.

The selected consolidated statement of operations data for the fiscal years ended June 30, 2007 and 2008 and the selected consolidated balance sheet data as of June 30, 2007 and 2008 have been restated to correct errors related to natural gas and crude oil derivatives that were previously accounted for as cash flow hedges that did not qualify as cash flow hedges for accounting purposes because our documentation did not meet hedge accounting documentation standards. The selected historical consolidated financial data for the nine months ended September 30, 2012 has also been restated to correct errors related to crude oil cash flow hedges that did not qualify for hedge accounting and errors related to accounting for our unevaluated properties and full cost pool. In addition, the selected historical consolidated financial data for the nine months ended September 30, 2012 have been recast to reflect measurement period adjustments made to our preliminary business combination accounting. See Note 3 to the unaudited interim consolidated financial statements for further information regarding the restatement and recast of the September 30, 2012 interim financial statements. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period. The historical operating results of the Company and Predecessor are not necessarily indicative of future operating results.

The following selected historical financial data should be read together with the information included under the headings “Capitalization” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the accompanying notes of the Company and Predecessor included elsewhere in this prospectus.

 

    Predecessor     Successor     Predecessor     Successor  
    Year Ended June 30,     July 1, 2011
through
December 21,
2011
    From
Inception
(November 14,
2011) through
December  31,

2011
    Nine Months
Ended
September 30,

2011
    Nine Months
Ended
September 30,

2012
 

(dollars in thousands except ratios)

  2007     2008     2009     2010     2011          
    (unaudited, as restated)                                  

(unaudited)

(as restated)

    (unaudited)  
                                          (as restated
and recast)
 

Statement of income (loss) and comprehensive income (loss) data:

                       

Revenues:

                       

Natural gas and natural gas liquids sales

    1,377,216        1,911,795        1,296,464        995,563        983,079        439,894        20,932        775,752        388,320   

Crude oil sales

    218,714        461,974        334,455        406,666        446,508        241,100        15,473        369,689        381,376   

Commodity derivatives

    130,310        (887,077     1,413,148        256,950        (126,874     157,726        18,496        176,947        66,123   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    1,726,240        1,486,692        3,044,067        1,659,179        1,302,713        838,720        54,901        1,322,388        835,819   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses:

                       

Lease operating

    191,216        286,975        260,997        226,172        208,787        121,834        5,320        144,752        170,048   

Production and ad valorem taxes

    103,859        149,290        103,848        98,122        107,144        60,591        3,537        79,198        62,965   

Depletion, depreciation and amortization

    527,841        706,989        910,279        591,378        536,748        342,604        18,233        425,446        497,098   

Impairment

    —          —          2,576,016        —          —          —          —          —          560,987   

Related party management fee

    —          —          —          —          —          —          —          —          15,000   

General and administrative

    83,175        132,321        37,309        101,872        114,075        437,511        142,780        105,760        112,618   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

    906,091        1,275,575        3,888,449        1,017,544        966,754        962,540        169,870        755,156        1,418,716   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

    820,149        211,117        (844,382     641,635        335,959        (123,820     (114,969     567,232        (582,897

Interest expense, net of capitalization

    (4,205     (22,727     (26,903     (38,560     (23,512     (12,161     —          (14,123     14   

Investment income and other (1)

    19,649        59,829        10,933        3,425        10,220        9,243        933        13,546        4,796   

 

44


Table of Contents
    Predecessor     Successor     Predecessor     Successor  
    Year Ended June 30,     July 1, 2011
through
December 21,
2011
    From
Inception
(November 14,
2011) through
December 31,

2011
    Nine Months
Ended
September 30,

2011
    Nine Months
Ended
September 30,

2012
 

(dollars in thousands except ratios)

  2007     2008     2009     2010     2011          
    (unaudited, as restated)                                  

(unaudited)

(as restated)

   

(unaudited)

(as restated
and recast)

 

Loss on early extinguishment of debt

    —          —          —          —          —          (77,413     —          —          (44,815
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes

    835,593        248,219        (860,352     606,500        322,667        (204,151     (114,036     566,655        (622,902

Income tax provision (benefit)

    350,598        107,110        (351,631     205,293        116,979        (85,188     (40,369     200,596        (220,508
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) from continuing operations

    484,995        141,109        (508,721     401,207        205,688        (118,963     (73,667     366,059        (402,394

Discontinued operations, net of taxes:

                       

Income (loss) from discontinued operations (2)

    3,534        19,610        (30,879     (16,140     —          —          —          —          —     

Gain (loss) on disposal of discontinued operations (3)

    753,107        (9,263     51,671        —          —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

    1,241,636        151,456        (487,929     385,067        205,688        (118,963     (73,667     366,059        (402,394

Other comprehensive income (loss):

                       

Foreign currency translation adjustment

    11,567        5,871        (6,937     (50     (130     (3     —          (135     —     

Foreign currency reclassification adjustments for realized gains

    (92,548     —          (9,391     1,678        262        3        —          264        —     

Unrealized holding gains (losses) from short-term investments, net of tax

    8,748        1,909        (24,854     3,414        8,439        (1,493     —          (1,388     —     

Reclassification adjustments for realized gains (losses) from short-term investments, net of tax

    (1,641     (4,840     951        (574     (5,307     —          —          (4,819     —     

Unrealized losses from cash flow hedges

    —          —          —          —          —          —          —          —          (12,245

Reclassification of realized gains (loss) from cash flow hedges

    —          —          —          —          —          —          —          —          2,241   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other comprehensive income (loss)

    (73,874     2,940        (40,231     4,468        3,264        (1,493     —          (6,078     (10,004
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total comprehensive income (loss)

    1,167,762        154,396        (528,160     389,535        208,952        (120,456     (73,667     359,981        (412,398
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Statement of cash flows data:

                       

Net cash provided by (used in):

                       

Operating activities

    1,101,118        1,950,217        1,129,735        1,298,600        1,426,645        410,554        (553,520     1,031,632        426,788   

Investing activities

    (1,321,860     (1,545,082     (1,256,620     (1,055,739     (991,092     (924,786     (6,897,175     (993,157     (1,072,100

Financing activities

    46,277        (45,000     (158,836     (20,138     (157,156     (95,000     7,577,424        (250,028     631,355   

Balance sheet data (end of period):

                       

Cash and cash equivalents

    56,098        415,347        130,512        353,161        631,632            126,729        369,506        112,772   

Total assets

    5,965,928        7,449,428        4,925,939        5,560,379        5,945,959            11,504,279        6,178,782        11,509,367   

Long-term debt (including the current portion)(4)

    911,440        866,440        715,000        695,000        695,000            3,595,000        1,248,000        4,265,000   

Shareholders’ equity

    3,333,271        3,487,667        2,477,621        2,867,156        2,776,108            4,074,213        2,981,168        3,683,079   

Other financial data:

                       

Capital expenditures

    1,968,578        2,087,721        1,518,594        1,120,279        1,587,755        919,648        2,561        1,555,788        1,090,182   

EBITDA(5)

    2,124,280        988,282        97,622        1,220,298        882,927        150,614        (95,803     1,006,224        (125,818

Adjusted EBITDA (5)

    2,165,013        1,976,336        1,575,773        1,329,907        1,268,157        340,241        106,902        890,708        568,024   

 

(1) Due to the economic downturn and deterioration of the real estate market, the obligors on two notes receivable defaulted on their respective notes, resulting in charges to impairment of $51.6 million in the fiscal year ended June 30, 2009.
(2) The pretax loss from operations of discontinued business related to Canada was $1.2 million and $17,000 for the years ended June 30, 2010 and 2009, respectively. The pretax losses related to the North Sea operations were $15.0 million and $30.9 million for the years ended June 30, 2010 and 2009, respectively.
(3) On August 28, 2008 the company sold Canadian assets, which represented the majority of oil and natural gas properties located in Canada, for a total sales price of $149.0 million, net of post-closing adjustments. The sale resulted in a gain of $56.7 million, net of post-closing adjustments and taxes. The Company closed its Calgary office and completed its withdrawal of all significant operations in Canada with this transaction. On May 15, 2009 all remaining oil and natural gas properties located in Canada were sold for a total sales price of $0.3 million, net of post-closing adjustments. This sale resulted in a loss of $5.1 million.
(4) Includes $553.0 million aggregate principal amount of outstanding shareholder subordinated notes as of September 30, 2011, which were discharged as part of the consideration for the Gulf Coast and Offshore Reorganization.

 

45


Table of Contents
(5) EBITDA is defined by us as net income, plus interest expense, net, provision for income taxes, depreciation, depletion and amortization. Adjusted EBITDA represents net income, plus interest expense, net, provision for income taxes and, depreciation, depletion and amortization, plus the adjustments set forth below. EBITDA and Adjusted EBITDA are not measurements of our financial performance under GAAP and should not be considered as alternatives to net income or other performance measures derived in accordance with GAAP, or as alternatives to cash flows from operating activities as measures of our liquidity. In addition, our measurement of EBITDA and Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Management believes that the presentation of EBITDA and Adjusted EBITDA provide useful information to investors regarding our results of operations because they assist in analyzing and benchmarking the performance and value of our business. We will also use Adjusted EBITDA as a measure to calculate certain financial covenants related to our RBL Revolver and the Second Lien Term Loan and certain covenants in the indenture governing the notes. See “Description of Other Indebtedness” and “Description of Notes.”

 

     EBITDA and Adjusted EBITDA have limitations as analytical tools, and you should not consider such measures either in isolation or as a substitute for net income, cash flow or other methods of analyzing our results as reported under GAAP. Some of these limitations are:

 

   

EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital needs;

 

   

EBITDA and Adjusted EBITDA do not reflect our interest expense, or the cash requirements necessary to service interest or principal payments, on our indebtedness;

 

   

EBITDA and Adjusted EBITDA do not reflect our tax expense or the cash requirements to pay our taxes;

 

   

EBITDA and Adjusted EBITDA do not reflect historical cash expenditures or future requirements for capital expenditures or contractual commitments;

 

   

EBITDA and Adjusted EBITDA do not reflect the impact on earnings or changes resulting from matters that we consider not to be indicative of our future operations;

 

   

although depreciation, depletion and amortization are non-cash charges, the assets being depreciated, depleted and amortized will often have to be replaced in the future and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements; and

 

   

other companies in our industry may calculate EBITDA and Adjusted EBITDA differently, limiting their usefulness as comparative measures.

 

     Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as discretionary cash available to us to reinvest in the growth of our business or as measures of cash that will be available to us to meet our obligations.

The following table provides an unaudited reconciliation of net income to EBITDA and Adjusted EBITDA:

 

    Predecessor     Successor     Predecessor     Successor  
    Year Ended June 30,     July  1,
2011
through
December
21, 2011
    From
Inception
(November
14, 2011
through
December
31, 2011
    Nine Months
Ended
September  30,
2011
    Nine  Months
Ended
September  30,
2012
 

(dollars in thousands)

  2007     2008     2009     2010     2011          
    (unaudited as restated)                                  

(unaudited)

(as restated)

   

(unaudited)

(as restated
and recast)

 
     

Net income (loss)

  $ 1,241,636      $ 151,456      $ (487,929   $ 385,067      $ 205,688      $ (118,963   $ (73,667   $ 366,059      $ (402,394

Interest expense (income), net

    4,205        22,727        26,903        38,560        23,512        12,161        —          14,123        (14

Provision for income taxes

    350,598        107,110        (351,631     205,293        116,979        (85,188     (40,369     200,596        (220,508

Depreciation, depletion and amortization

    527,841        706,989        910,279        591,378        536,748        342,604        18,233        425,446        497,098   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

    2,124,280        988,282        97,622        1,220,298        882,927        150,614        (95,803     1,006,224        (125,818

Adjustment for unrealized hedging (gains) losses

    (13,546     830,420        (1,166,169     109,059        350,288        (93,758     (12,795     (117,266     53,713   

Adjustment for (gain) loss on short-term investment

    625        (397     (1,571     (6,754     (2,949     (325     —          1,750        —     

Adjustment for non-cash stock compensation expense

    53,654        158,031        69,875        7,304        37,891        —          —          —          18,976   

Adjustment for acquisition related expenses

    —          —          —          —          —          275,131        215,500        —          —     

Adjustments for management and advisory fees paid to the Sponsor and other investors

    —          —          —          —          —          —          —          —          15,000   

Adjustment for fees paid for Sarbanes-Oxley Act of 2002 compliance

    —          —          —          —          —          —          —          —          351   

Non-cash loss on early extinguishment of debt

    —          —          —          —          —          8,579        —          —          44,815   

Provision to reduce carrying value of oil and natural gas properties

    —          —          2,576,016        —          —          —          —          —          560,987   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 2,165,013      $ 1,976,336      $ 1,575,773      $ 1,329,907      $ 1,268,157      $ 340,241      $ 106,902      $ 890,708      $ 568,024   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

46


Table of Contents

Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis in conjunction with “Selected Historical Consolidated Financial Data” and the historical consolidated financial statements and related notes of the Company included elsewhere in this prospectus. This discussion and analysis contains forward-looking statements regarding industry outlook, our expectations regarding our future performance, liquidity and capital resources and other non-historical statements that are based on management’s current expectations, estimates and projections about our business and operations. Our actual results may differ materially from those contained in, or implied by, any forward-looking statements. These forward-looking statements are subject to numerous risks and uncertainties, including, but not limited to, the risks and uncertainties described in the “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” sections of this prospectus.

Basis of Presentation

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. As a result of the matters described below, certain comparisons between periods may be difficult or not possible.

 

   

On November 14, 2011, Samson Resources Corporation was formed for the purpose of acquiring all of the issued and outstanding common stock of the Predecessor, which occurred on December 21, 2011. The Acquisition was accounted for as a business combination and the assets and liabilities acquired were recorded at their estimated acquisition date fair value, impacting the comparability of the financial statements of Samson Resources Corporation with the financial statements of the Predecessor.

The Acquisition was accounted for as a business combination and the assets and liabilities acquired were recorded at their estimated acquisition date fair value. The acquired assets and liabilities were recorded using a different basis than what was previously recorded by the Predecessor, which impacts the comparability of the financial statements of Samson with the financial statements of the Predecessor.

The results of operations of Samson reflected in the Successor financial statements for the nine months ended September 30, 2012 do not include the Offshore and Gulf Coast operations of the Predecessor, whereas the results of operations of the Predecessor for the nine months ended September 30, 2011 and for all earlier periods presented include the Predecessor’s Offshore and Gulf Coast operations.

 

   

In January 2011, the Predecessor sold substantially all of its oil and natural gas properties located in the Permian Basin in two separate sales. The total sales price was approximately $468.1 million. No gain or loss was recorded. The transaction resulted in a decrease to the full cost pool and impacted the depletion rate.

 

   

The comparability of our Predecessor’s transitional period presented is impacted by the fact that the period from July 1, 2011 to December 21, 2011 (the “2011 transitional period”) presented includes 174 days, up to the Acquisition date of December 21, compared to the 184 days included in the 2010 transition period. For ease of discussion, the 174 day period is referred to as the six month 2011 period or the 2011 transitional period.

Overview

We are a private oil and natural gas company engaged in the development, exploration, acquisition and opportunistic divestiture of crude oil and natural gas properties. We operate oil and natural gas properties as one business and manage operations through distinct regions, which we defined primarily by geographic areas. We have approximately 2.9 million net acres leased, primarily located in our core areas of operations in the Rockies, Mid-Continent, and East Texas regions of the United States.

 

47


Table of Contents

We derive substantially all of our revenues from the sale of natural gas, NGLs and crude oil that is produced through our interests in properties located onshore in the United States and related hedging activities. Unless otherwise stated, operating results for natural gas include NGLs. Natural gas and crude oil prices are volatile and are influenced by many factors outside of our control. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations for oil and natural gas, we use derivative instruments to economically hedge future sales prices on a significant portion of our crude oil and natural gas production. Our derivative financial instruments have historically included fixed price swap agreements, costless collars, and basis swaps.

Our financial and operating performance for the nine months ended September 30, 2012 included the following:

 

   

Total revenues of approximately $835.8 million, compared to approximately $1,322.4 million for the Predecessor nine months ended September 30, 2011.

 

   

Average daily production of 668,339 Mcfe/d, compared to 727,341 Mcfe/d for the Predecessor nine months ended September 30, 2011.

 

   

Impairment of $561.0 million was recognized. No impairment was recorded for the comparable Predecessor period.

 

   

Long-term debt increased $670.0 million during the nine months ended September 30, 2012. Proceeds were used primarily to fund our drilling and development programs.

 

   

Beginning in the third quarter of 2012, we designated a portion of our commodity hedging derivatives as cash flow hedges.

Our financial and operating performance for the period from inception (November 14, 2011) through December 31, 2011, for the Predecessor period from July 1, 2011 through December 21, 2011 and for the Predecessor year ended June 30, 2011 included the following:

 

   

Natural gas and oil sales of approximately $54.9 million, $838.7 million, and $1,302.7 million, respectively.

 

   

Average daily production of 714,400 Mcfe/d, 710,908 Mcfe/d, and 713,764 Mcfe/d, respectively.

Industry Trends and Uncertainties

Our performance is generally impacted by several factors, including:

 

   

the volatility of natural gas and oil prices;

 

   

transportation capacity constraints and interruptions;

 

   

the level of consumer demand and overall economic activity;

 

   

the competitiveness of alternative fuels;

 

   

weather conditions and the impact of weather-related events; and

 

   

government regulations and taxes.

Key Factors Affecting Our Results of Operations

Core Areas of Operations

We are concentrating drilling efforts and capital expenditures in our oil rich basins, including the Powder River, Green River and Williston basins. We completed our first horizontal well in Ft. Union in the Green River basin during the first quarter of 2012 and plan to aggressively drill in this play in the near future. We have identified liquids-rich sand plays in our East Texas region and oil plays in the Tonkawa and Mississippian formations in the Mid-Continent region, and anticipate increasing drilling locations in these plays.

 

48


Table of Contents

We completed a total of 327 (101 net) wells during the nine months ended September 30, 2012. A total of 100 (66 net) of the wells completed in 2012 related to properties we operate and 227 of the completed wells (35 net) were associated with non-operated properties. We are actively drilling in our core areas of operations with a concentration in the Rockies, where approximately 55% of the total well completions during the nine- month period occurred. We expect our total capital expenditures, excluding capitalized interest and capitalized internal costs, for the fourth quarter of 2012 and fiscal 2013 to approximate $200.0 million and $758.5 million, respectively.

Commodity Prices

Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. Our 2012 results continue to be impacted by lower realized prices.

As a result of continued low oil and natural gas prices, we recognized ceiling test write-downs during the nine months ended September 30, 2012. We capitalize the costs to acquire, find and develop our oil and natural gas properties under the full cost method of accounting for oil and natural gas activities. The net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of estimated future net cash flows from proved reserves. The prices used to estimate future net cash flows is the unweighted average of natural gas and oil prices on the first day of each month within the 12-month period prior to the date the ceiling test is performed. If net capitalized costs of our oil and natural gas properties exceed this limit, we must charge the amount of the excess to earnings with a ceiling test impairment. We recorded ceiling test impairments totaling $561.0 million ($362.4 million after-tax) for the nine months ended September 30, 2012.

We have received a third party reserve report prepared as of December 31, 2012, which reflected total proved reserves of $2,760 million using pricing required by the SEC for ceiling test computations. Our proved reserves have decreased by approximately $817 million from the amount used in our September 30, 2012 ceiling test. Approximately $660 million of the decline related to our divestiture of properties in the Bakken that occurred in the fourth quarter of 2012. Our full cost pool will be reduced by the difference between the sales proceeds received of approximately $680 million and the carrying value of our unproved properties sold, which approximates $181 million. The reduction in the present value of our proved oil and gas reserves resulting from the sale of Bakken properties exceeds the expected reduction of our full cost pool. Consequently, the divestitures described above will have a negative impact to our ceiling test calculation for the fourth quarter of 2012. Based on the information summarized above, we believe it is probable that a full cost ceiling impairment will be recorded as a result of our fourth quarter 2012 ceiling test and the impairment expense may be material. For example, if all other inputs to the ceiling test remained constant, the factors described above would result in an additional after tax impairment of approximately $300 million at December 31, 2012.

Although a ceiling test impairment does not impact cash flows from operations, it does reduce our shareholders’ equity. Once recorded, a ceiling test impairment is not reversible at a later date even if oil and natural gas prices increase. Our future depletion rate will be lower than it otherwise would have been in the future as a result of the impairment charges recorded in 2012. Continued low or declining commodity prices, or other factors impacting our operations, could result in additional ceiling test impairments in subsequent periods.

For the remainder of 2012, we experienced low natural gas prices and continued weakness in NGLs realizations. A significant portion of our natural gas and oil volumes are hedged at prices that exceed the current market prices and we are well positioned to continue to execute our business strategy of developing regional resource plays at costs that generate attractive returns.

Derivative Financial Instruments

We utilize commodity-based derivative instruments to manage our exposure to changes in expected future cash flows from forecasted sales of crude oil, natural gas and NGLs attributable to commodity price risk. Although all of our derivative activity is designed to reduce our exposure to declining prices, we designated only

 

49


Table of Contents

a portion of our derivatives as cash flow hedges for accounting purposes beginning in the third quarter of 2012. Changes in the fair value of derivatives instruments not designated as accounting hedges are recognized as gains or losses in the earnings of the periods in which they occur, accordingly we believe this will result in future earnings that are more volatile. The effective portion of changes in fair values of our derivatives designated as cash flow hedges are recorded through other comprehensive income and do not impact net income until the underlying physical transaction settles.

The following table sets forth our open derivative positions as of September 30, 2012 for derivatives designated as cash flow hedging instruments:

 

     Natural Gas Fixed Price Swaps      Crude Oil Fixed Price Swaps      Natural Gas Basis Swaps  

Period

   Volume
(MMBtu)
     Weighted
Average Price
($/MMBtu)
     Volume
(MBBls)
     Weighted
Average  Price
($/BBls)
     Volume
(MMBtu)
     Weighted
Average  Price
($/MMBtu)
 

Q4 2012

     13,571       $ 3.62         230       $ 92.81         8,900       $ 0.30   

Q1-Q4 2013

     67,316       $ 3.63         913       $ 92.47         16,425       $ 0.18   

Q1-Q4 2014

     14,473       $ 4.07         913       $ 91.66         —           —     

Q1-Q4 2015

     13,184       $ 4.07         365       $ 91.30         —           —     

Q1-Q4 2016

     12,108       $ 4.07         —           —           —           —     

Q1-Q4 2017

     3,650       $ 3.93         —           —           —           —     

The following table sets forth our net open derivative positions as of September 30, 2012 for derivatives not designated as accounting hedges:

 

     Natural Gas Fixed Price Swaps      Crude Oil Fixed Price Swaps      Natural Gas Basis Swaps  

Period

   Volume
(MMBtu)
     Weighted
Average Price
($/MMBtu)
     Volume
(MBBls)
     Weighted
Average  Price
($/BBls)
     Volume
(MMBtu)
     Weighted
Average  Price
($/MMBtu)
 

Q4 2012

     12,966       $ 4.22         1,334       $ 90.34         920       $ 0.63   

Q1-Q4 2013

     51,803       $ 3.76         5,751       $ 91.59         —           —     

Q1-Q4 2014

     58,273       $ 4.06         4,745       $ 91.23         —           —     

Q1-Q4 2015

     20,484       $ 3.99         913         92.83         —           —     

Q1-Q4 2016

     19,428       $ 3.99         —           —           —           —     

Q1-Q4 2017

     10,950       $ 3.92         —           —           —           —     

 

       Ethane Fixed Price Swaps        Propane Fixed Price Swaps        Natural Gasoline
Fixed Price Swaps
 

Period

     Volume
(Tgal)
       Weighted
Average
Price

($/Tgal)
       Volume
(Tgal)
       Weighted
Average
Price

($/Tgal)
       Volume
(Tgal)
       Weighted
Average
Price

($/Tgal)
 

Q4 2012

       6,762         $ 0.36           6,955         $ 0.90           1,932         $ 2.22   

Q1-Q4 2013

       19,163         $ 0.41           21,462         $ 1.03           7,665         $ 2.10   

Source of Our Revenues

We derive substantially all of our revenues from the sale of natural gas and crude oil that is produced through our interests in properties located onshore in the United States and related hedging activities. Natural gas and crude oil prices are volatile and are influenced by many factors outside of our control. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations for oil and natural gas, we use derivative instruments as discussed above. Our derivative financial instruments have historically included fixed price swap agreements and basis swaps. The fair value of these derivatives was a net liability of $52.7 million at September 30, 2012. We expect continued volatility in the fair value of these derivative contracts.

 

50


Table of Contents

Principal Components of Our Cost Structure

Oil and Natural Gas Production Costs. These are costs incurred in extracting oil or natural gas from our reserves. Oil and natural gas production costs include direct operating expenses, which include lease operating expenses and compensation expenses for all field personnel, production and ad valorem taxes and workover expenses.

Depreciation, Depletion and Amortization (“DD&A”) of Oil and Natural Gas Properties. This includes the depletion of costs related to the acquisition of property or property mineral rights and the amortization of intangible drilling costs incurred with developing our reserves.

Depreciation and Amortization of Other Property and Equipment. This is calculated using the straight-line method over the estimated useful lives of other property and equipment ranging for periods from three to 32 years, as applicable.

General and Administrative. These costs include compensation expenses, office expenses and other expenses for all office personnel, but exclude internal costs capitalized to our oil and natural gas properties.

Impairment. We evaluate the impairment of our proved natural gas and oil properties on a company-level basis. Property impairment charges result from the application of the ceiling test under the full cost accounting rules, which we are required to calculate on a quarterly basis. The ceiling test requires that a non-cash impairment charge be taken to reduce the carrying value of natural gas and oil properties if the carrying value exceeds a defined cost-center ceiling. Because current commodity prices, and related calculations of the discounted present value of reserves, are significant factors in the full cost ceiling test, impairment charges may result from declines in natural gas and oil prices.

Interest Expense. This expense includes interest payments paid on bank and insurance company loans, interest on notes payable to shareholders, amortization of loan commitment and other fees, and interest accrued for royalty owners and taxing authorities, but excludes interest expenses capitalized to our natural gas and oil properties. We have financed and expect to finance a portion of our working capital requirements and acquisitions with borrowings under the RBL Revolver. As a result, we have and will continue to incur interest expense that is affected by the level of drilling, completion and acquisition activities, as well as fluctuations in interest rates and our financing decisions. We will likely continue to incur significant interest expense as we continue to grow. From time to time, we have engaged in the activity of entering into interest rate swaps to manage our exposure to interest rate fluctuations.

Recent Developments

On December 11, 2012, we announced the retirement of our President, Chief Executive Officer and Director, David Adams, effective December 31, 2012. We also announced that we were (i) closing our Midland, Texas office resulting in a severance of all employees located in Midland, Texas and all field or field operations employees assigned to the Permian region and (ii) undertaking an overall reduction in force that impacted about 10% of our workforce (inclusive of Midland/Permian).

As a result of the workforce reduction, we currently estimate that we will record restructuring charges of approximately $47.0 million, which are expected to be recorded primarily in the fourth quarter of 2012. Our estimated restructuring charges are based on a number of assumptions. Actual results may differ materially from our expectations and additional charges not currently expected may be incurred in connection with, or as a result of, these reductions.

On December 20, 2012 we closed two sales of properties in the Williston Basin for total consideration of $680.0 million. The net sales proceeds were reflected as a reduction of oil and gas properties, with no gain or loss recognized.

 

51


Table of Contents

We have not yet completed our impairment evaluations for the fourth quarter of 2012. Our annual impairment review of our unevaluated property value is ongoing and we expect to complete our review in March 2013. Consequently, we do not know the amount (if any) of value associated with impaired unevaluated properties that will be transferred to our full cost pool and subject to the ceiling test limitation. In addition, we have not completed other work necessary to estimate or project what (if any) impairment may be recorded as a result of our December 31, 2012 ceiling test.

We have received a third party reserve report from Netherland Sewell & Associates, Inc. prepared as of December 31, 2012, which reflected total proved reserves of $2,760 million using pricing required by the SEC for ceiling test computations. Our proved reserves have decreased by approximately $817 million from the amount used in our September 30, 2012 ceiling test. Approximately $660 million of the decline related to our divestiture of properties in the Bakken that occurred in the fourth quarter of 2012. Our full cost pool will be reduced by the difference between the sales proceeds received of approximately $680 million and the carrying value of our unproved properties sold, which approximates $181 million. The reduction in the present value of our proved oil and gas reserves resulting from the sale of the Bakken properties exceeds the expected reduction of our full cost pool. Consequently, the divestitures described above will have a negative impact to our ceiling test calculation for the fourth quarter of 2012. Based on the information summarized above, we believe it is probable that a full cost ceiling impairment will be recorded as a result of our fourth quarter 2012 ceiling test and the impairment expense may be material. For example, if all other inputs to the ceiling test remained constant, the factors described above would result in an additional after tax impairment of approximately $300 million at December 31, 2012.

 

52


Table of Contents

Results of Operations

Successor Nine Months Ended September 30, 2012 Compared to Predecessor Nine Months Ended September 30, 2011

The following table sets forth selected operating data of the Successor and Predecessor for the nine months ended September 30, 2012 and September 30, 2011, respectively (in thousands, except production data).

 

     Successor      Predecessor  
     Nine Months
Ended
September 30, 2012
     Nine Months
Ended
September 30, 2011
 
     (as restated and
recast)
     (as restated)  

Revenues

       

Natural gas and natural gas liquids sales

   $ 388,320       $ 775,752   

Crude oil sales

     381,376         369,689   

Commodity derivatives

     66,123         176,947   
  

 

 

    

 

 

 

Total Revenue

     835,819         1,322,388   

Operating expenses

       

Lease operating

     170,048         144,752   

Production and ad valorem taxes

     62,965         79,198   

Depreciation, depletion and amortization

     497,098         425,446   

Impairment

     560,987           

Related party management fee

     15,000           

General and administrative

     112,618         105,760   
  

 

 

    

 

 

 

Total operating costs

     1,418,716         755,156   

Interest income (expense), net of capitalization

     14         (14,123

Other income

     4,796         13,546   

Loss on early extinguishment of debt

     (44,815        

Income tax provision (benefit)

     (220,508      200,596   
  

 

 

    

 

 

 

Net income (loss)

   $ (402,394    $ 366,059   
  

 

 

    

 

 

 

Production data:

       

Gas (Bcf)(a)

     155.1         173.8   

Oil (MMBbl)

     4.6         4.1   

Net Production (Bcfe) (b)

     182.5         198.6   

Production/day:

       

Gas mcf/d (a)

     567,972         636,505   

Oil B/d

     16,728         15,139   

Mcfe per day (b)

     668,339         727,341   

Price (before the effects of hedges):

       

Gas ($ per Mcf)

   $ 2.50       $ 4.46   

Oil ($ per barrel)

     83.50         89.45   

Combined production ($ per Mcfe)

     4.22         5.77   

Price (after the effects of hedges):

       

Gas ($ per Mcf)

   $ 3.36       $ 4.96   

Oil ($ per barrel)

     80.71         83.03   

Combined production ($ per Mcfe)

     4.86         6.07   

 

53


Table of Contents
     Successor      Predecessor  
     Nine Months
Ended
September 30, 2012
     Nine Months
Ended
September 30, 2011
 
     (as restated and
recast)
     (as restated)  

Average unit cost per combined production ($ per Mcfe):

       

Production costs:

       

Lease operating expense

   $ 0.93       $ 0.73   

Production taxes

     0.35         0.40   
  

 

 

    

 

 

 

Total

   $ 1.28       $ 1.13   
  

 

 

    

 

 

 

Depreciation, depletion and amortization

   $ 2.72       $ 2.14   

General and administrative expenses, net

   $ 0.62       $ 0.53   

Related party management fee

   $ 0.08       $   

 

(a) Natural gas volumes and prices include natural gas liquids for the periods presented.
(b) Oil is converted to Mcfe using the industry standard conversion rate of one barrel of oil to six thousand cubic feet of natural gas.

Oil and natural gas revenues. Oil and natural gas revenue was $769.7 million for the nine months ended September 30, 2012, a decrease of $375.7 million, or approximately 33%, from the $1,145.4 million of oil and natural gas revenues recorded for the Predecessor for the nine months ended September 30, 2011. This decrease resulted primarily from worsening commodity prices during 2012 and decreases in production due to both the Gulf Coast and Offshore assets which were retained by the former shareholders of the Predecessor as part of the Acquisition and the cessation of new natural gas drilling during 2012. Offsetting these factors was increased crude oil production volumes, primarily in the Rockies region, during 2012. Specific factors affecting commodity revenues include the following:

 

   

Total natural gas production was 155.1 Bcf for the nine months ended September 30, 2012, a decrease of 18.7 Bcf, or approximately 11%, from 173.8 Bcf for the Predecessor’s nine months ended September 30, 2011. The absence of natural gas production related to the Gulf Coast and Offshore assets contributes 13.34 Bcf to the total decrease in natural gas production volumes during the period. The remaining decrease in natural gas production volumes was attributable to natural declines in production in existing fields and the cessation of new natural gas drilling, reflecting our shift towards oil and NGLs production streams.

 

   

Average realized natural gas price (excluding the effects of derivative activities) was $2.50 per Mcf during the nine months ended September 30, 2012, a decrease of approximately 44% from $4.46 per Mcf realized by the Predecessor during the nine months ended September 30, 2011.

 

   

Total oil production was 4.6 MMBbls for the nine months ended September 30, 2012, an increase of 0.5 MMBbls, or approximately 12%, from 4.1 MMBbls for the Predecessor’s nine months ended September 30, 2011. The increase in production volumes was attributable to our oil-intensive drilling program, with an increase of 450 producing wells (134 net) between September 30, 2011 and September 30, 2012. Increased production volumes from new wells were partially offset by a decrease of 1.0 MMBbls of crude oil production related to the Gulf Coast and Offshore assets not acquired by the Successor as part of the Acquisition.

 

   

Average realized oil price (excluding the effects of derivative activities) was $83.50 per Bbl during the nine months ended September 30, 2012, a decrease of approximately 7% from $89.45 per Bbl realized by the Predecessor during the nine months ended September 30, 2011.

Effect of cash flow hedges on revenues. Beginning in the third quarter of 2012, we designated a portion of our commodity hedging derivative portfolio as cash flow hedges. Changes in the fair value of derivatives

 

54


Table of Contents

designated as cash flow hedges are transferred into earnings in the period in which the hedged transaction occurs. The impact to revenue during the third quarter of 2012 related to the change in fair value of cash flow hedges for production which occurred was $5.3 million. Additionally, a loss of $1.2 million was recognized in commodity derivatives due to ineffectiveness in our cash flow hedges.

Gain on derivatives not designated as accounting hedges. Our earnings are affected by the changes in value of our derivatives portfolio which can be volatile. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses. For the nine months ended September 30, 2012 the fair value of our derivatives not designated as accounting hedges decreased by $44.0 million, of which $81.0 million was a mark-to-market gain and $125.0 million related to cash settlements. The Predecessor recognized a $117.2 million gain in derivatives not designated as accounting hedges for the comparable period in 2011, comprised of a $176.9 million mark-to-market gain, offset by net cash settlements of $59.7 million.

Operating Expenses

Among the cost components of production expenses, we have some control over lease operating expenses and workover costs on properties we operate, but production and ad valorem taxes are directly related to volume and commodity price changes, but can also be affected by credits received.

Lease operating expenses. Lease operating expenses were $170.0 million, or $0.93 per Mcfe, for the nine months ended September 30, 2012 and $144.8 million, or $0.73 per Mcfe, for the Predecessor nine months ended September 30, 2011. A major contributor to the increase in lease operating expense during 2012 related to $31.0 million of net proceeds related to hurricane reimbursements which were netted against lease operating expense in 2011. The increase in lease operating expenses was also attributable to higher levels of drilling and operating activity in the Rockies, Mid-Continent and East Texas regions, reflecting the higher operating costs associated with oil production as compared to natural gas production. For the nine months ended September 30, 2012, a total of 324 new wells (95 net) were drilled (91 operated wells (61 net) and 233 non-operated wells (34 net)). Workover expenses were approximately $22.3 million for the Successor and $39.9 million for the Predecessor for the nine months ended September 30, 2012 and 2011, respectively. The decrease in workover expense was attributable to the absence of workover expense related to the Gulf Coast and Offshore assets in 2012.

Production and ad valorem taxes. Production taxes per unit of production were $0.35 per Mcfe during the nine months ended September 30, 2012, a decrease of approximately 13% from $0.40 per Mcfe during the nine months ended September 30, 2011. The decrease was directly related to the decrease in commodity prices and revenue. Over the same period, our per Mcfe prices (excluding the effects of derivatives) decreased approximately 27%.

Depreciation, depletion and amortization expense. DD&A expense was $497.1 million for the nine months ended September 30, 2012, an increase of $71.7 million, or approximately 17%, from $425.4 million for the Predecessor’s nine months ended September 30, 2011. On a per unit basis, DD&A expense was $2.72 per Mcfe and $2.14 per Mcfe for the same periods, respectively. The increase in depletion expense was primarily due to the higher per unit rate resulting from the increase in the estimated completion costs associated with our proved undeveloped reserves. In addition, the Acquisition and interest capitalized on related borrowings have resulted in large increases in value reflected for our costs not subject to amortization. As we develop our oil and natural gas properties, or impair our unevaluated costs, increases to our depletion base occur. Additionally, our shift towards focusing a capital program on oil rich resources has resulted in additional costs to be depleted, increasing the rate.

Impairment. Our net book value for our oil and natural gas properties exceeded the ceiling amount and an impairment expense of $561.0 million for the nine months ended September 30, 2012 was recorded to reduce the

 

55


Table of Contents

carrying value of oil and natural gas properties. No impairments were required for the comparable Predecessor periods in 2011.

Management fee. We pay a quarterly management fee of $5.0 million to our private equity sponsors beginning in 2012 for a year-to-date impact of $15.0 million.

General and administrative expenses. General and administrative expenses were approximately $112.6 million for the nine months ended September 30, 2012, an increase of $6.8 million, or approximately 6%, from $105.8 million for the Predecessor’s nine months ended September 30, 2011. On a per unit basis, G&A expenses were $0.62 per Mcfe and $0.53 per Mcfe for the same periods, respectively. Drivers to the increase in general and administrative expenses in 2012 include transition costs unique to the Successor such as consulting fees related to the implementation of new ERP software, business reorganization and the Sarbanes-Oxley Act 2002 compliance effort. Additionally, non-cash compensation expense related to our stock options awarded to employees contributed to the increase in general and administrative expenses. We recorded $19.0 million of expense related to our stock option plans for the nine months ended September 30, 2012 compared to expense of $17.1 million recorded in the comparable 2011 period related to the stock appreciation rights of the Predecessor.

Interest expense. We incurred interest cost of $219.0 million for the nine months ended September 30, 2012, an increase of $154.4 million from the $64.6 million incurred by the Predecessor for the nine months ended September 30, 2011. The increase in interest cost was the result of increased debt balances outstanding in 2012 as well as higher average weighted interest rates on the Successor’s borrowings as compared to the Predecessor. Offsetting the increase in gross interest cost incurred was the higher amounts of interest cost capitalized in 2012. During the nine months ended September 30, 2012, our significant unevaluated costs required us to capitalize all interest cost incurred, compared to only $49.9 million capitalized for the Predecessor during the comparable period.

Loss on early extinguishment of debt. During the nine months ended September 30, 2012, we recorded a non-cash expense of approximately $44.8 million related to the early payment of the Bridge Facility with proceeds from the notes issued in February 2012.

Income tax provisions. We recognized an income tax benefit of $220.5 million for the nine month period ended September 30, 2012, compared to the Predecessor’s income tax expense of $200.6 million for the nine months ended September 30, 2011, reflecting the change in pre-tax income (loss) for the period. The effective income tax rate for both the Successor and the Predecessor’s three months ended September 30, 2012 and 2011 was approximately 35%.

 

56


Table of Contents

2011 Transitional Period

The following table sets forth selected operating data of the Successor and Predecessor for the periods indicated (in thousands, except production data).

 

     Successor      Predecessor  
   From Inception
(November  14, 2011)
through
December 31, 2011(c)
     July 1, 2011
through
December 21,
2011
    Six Months
Ended
December 31,
2010
 
                  (unaudited)  

Revenues

         

Natural gas and natural gas liquids sales

   $ 20,932       $ 439,894      $ 459,572   

Crude oil sales

     15,473         241,100        196,718   

Commodity derivatives

     18,496         157,726        (47,482
  

 

 

    

 

 

   

 

 

 

Total Revenue

     54,901         838,720        608,808   

Operating expenses

         

Lease operating

     5,320         121,834        124,379   

Production and ad valorem taxes

     3,537         60,591        52,626   

Depreciation, depletion and amortization

     18,233         342,604        262,572   

General and administrative

     142,780         437,511        57,502   
  

 

 

    

 

 

   

 

 

 

Total operating costs

     169,870         962,540        497,079   

Interest expense, net of capitalization

             (12,161     (17,303

Other income

     933         9,243        1,631   

Loss on early extinguishment of debt

             (77,413       

Income tax (benefit) provision

     (40,369      (85,188     38,423   
  

 

 

    

 

 

   

 

 

 

Net income (loss)

   $ (73,667    $ (118,963   $ 57,634   
  

 

 

    

 

 

   

 

 

 

Production data:

         

Gas (Bcf) (a)

     6.1         107.3        114.3   

Oil (MMBbl)

     0.2         2.7        2.5   

Net Production (Bcfe) (b)

     7.1         123.7        129.4   

Production/day:

         

Gas mcf/d (a)

     610,600         616,908        621,125   

Oil B/d

     17,300         15,667        13,663   

Mcfe per day (b)

     714,400         710,908        703,103   

Price (before the effects of hedges):

         

Gas ($ per Mcf)

   $ 3.43       $ 4.10        4.02   

Oil ($ per barrel)

     89.44         88.44        78.25   

Combined production ($ per Mcfe)

     5.10         5.51        5.07   

Price (after the effects of hedges):

         

Gas ($ per Mcf)

   $ 4.55       $ 4.76      $ 5.59   

Oil ($ per barrel)

     82.95         85.73        81.50   

Combined production ($ per Mcfe)

     5.89         6.02        6.52   

Average unit cost per combined production ($ per Mcfe):

         

Production costs:

         

Lease operating expense

   $ 0.75       $ 0.98      $ 0.96   

Production taxes

     0.50         0.49        0.41   
  

 

 

    

 

 

   

 

 

 

Total

   $ 1.25       $ 1.47      $ 1.37   
  

 

 

    

 

 

   

 

 

 

Depreciation, depletion and amortization

   $ 2.57       $ 2.77      $ 2.03   

General and administrative expenses, net

   $ 20.11       $ 3.54      $ 0.44   

 

(a) Natural gas volumes and prices include natural gas liquids for the periods presented.

 

57


Table of Contents
(b) Oil is converted to Mcfe using the industry standard conversion rate of one barrel of oil to six thousand cubic feet of natural gas.
(c) This period includes Acquisition related costs incurred prior to December 21, 2011.

Successor’s Results of Operations (ten-day period)

We completed the Acquisition on December 21, 2011. As a result, information for the Successor period shown in the table above includes production volumes and production related revenues and expenses for the ten day period from December 22, 2011 to December 31, 2011, excluding production related to the Gulf Coast and Offshore assets.

Oil and natural gas revenues. Oil and natural gas revenue of $36.4 million for the ten-day period was comprised of sales of natural gas of $20.9 million and sales of crude oil of $15.5 million. Production for the ten-day period was 714.4 Mcfe a day, consistent with production of the Predecessor immediately preceding the sale.

Gain/loss on derivatives. Our earnings are affected by the changes in value of our derivatives portfolio, which can be volatile. To the extent the future commodity price outlook declines between measurement periods, we have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we have mark-to-market losses. For the ten-day period from December 22, 2011 through December 31, 2011, the fair value of our derivatives increased by $18.5 million, of which $12.8 million was a mark-to-market gain and $5.7 million related to cash settlements.

Operating Expenses

As stated above, we completed the Acquisition on December 21, 2011. As a result, the table above shows production related expenses (such as lease operating expenses, production and ad valorem taxes and depletion, depreciation and amortization) for the Successor for the ten-day period from December 22, 2011 to December 31, 2011. Certain expenses, however, related to the Acquisition (included in general and administrative expenses) were incurred from the period of inception (November 14, 2011), for the Successor through December 31, 2011.

Lease operating expenses. We incurred lease operating expenses of $5.3 million or $0.75 per Mcfe for the ten day period following the Acquisition. The decrease in the per unit rate is mostly related to the timing of expenses incurred during the ten day Successor period.

Production and ad valorem taxes. We incurred production and ad valorem taxes of $3.5 million or $0.50 per Mcfe for the ten day period following the Acquisition. The per unit rate is consistent with the per unit rate incurred by the Predecessor for the period immediately preceding the Acquisition.

Depreciation, depletion and amortization expense. Our DD&A expenses for the ten day period was $18.2 million, or $2.57 per Mcfe. The decrease in the per Mcfe rate for the Successor as compared to that of the Predecessor for the period immediately preceding the Acquisition is due to the revaluation of the oil and natural gas properties at fair value during the business combination, resulting in a lower depletion base following the Acquisition.

General and administrative expenses. We incurred $142.8 million in general and administrative expenses from inception (November 14, 2011) through December 31, 2011. We incurred $137.4 million of expenses related to the Acquisition or related activities.

Interest expense. Interest cost of $7.7 million was incurred, related to our $3,595.0 million of long-term debt, all of which was capitalized.

 

58


Table of Contents

Income tax provision. We recognized an income tax benefit of $40.4 million for the period ending December 31, 2011, resulting in an effective tax rate of 35%.

Predecessor’s Results of Operations—Period from July 1, 2011 Through December 21, 2011 Compared to the Six Months Ended December 31, 2010

The comparability of our Predecessor’s results of operations among the periods presented is impacted by the fact that the 2011 transition period presented includes 174 days, up to the Acquisition date of December 21, 2011 compared to the 184 days included in the 2010 transition period. For ease of discussion, the 174 day period is referred to as the six month 2011 period or the 2011 transition period.

Oil and natural gas revenues. Oil and natural gas revenue was $681.0 million for the 2011 transition period, an increase of $24.7 million, or approximately 4% from the $656.3 million of oil and natural gas revenues recorded for the six months ended December 31, 2010. This increase in sales resulted primarily from increased crude oil production coupled with increasing crude oil prices during the period. Specific factors affecting commodity revenues include the following:

 

   

Total natural gas production was 107.3 Bcf for the period ending December 21, 2011, a decrease of 7 Bcf, or 6%, from 114.3 Bcf for the comparable period in 2010. Gas production between the two periods was steady with daily production of 616,908 Mcfe/day for the 2011 transition period compared to 621,125 Mcfe/day for the 2010 six month period. The 0.7% decrease in volumes is mostly due to the ten fewer days of production in the 2011 comparable period.

 

   

Average realized natural gas price (excluding the effects of derivative activities) was $4.10 per Mcf during the transition period ending December 21, 2011, an increase of approximately 2% from the $4.02 per Mcf realized during the six months ended December 31, 2010.

 

   

Total oil production was 2.7 MMBbl for the 2011 transition period, an increase of 0.2 MMBbl, or approximately 8% from 2.5 MMBbl for the six months ending December 31, 2010. Daily oil production increased approximately 15% in 2011, from 13.7 thousand barrels of oil per day to 15.7 thousand barrels of oil per day, consistent with our focus to concentrate on oil rich production areas.

 

   

Average realized crude oil prices (excluding the effects of derivative activities) was $88.44 per Bbl during the period ending December 31, 2011, an increase of approximately 13% from the $78.25 per Bbl realized during the comparable period in 2010.

Gain/loss on derivatives. The Predecessor’s earnings were affected by the changes in value of their derivatives portfolio, which could be volatile. To the extent the future commodity price outlook declined between measurement periods, the Predecessor recognized a mark-to-market gain, while to the extent future commodity price outlook increased between measurement periods, a mark-to-market loss was recorded by the Predecessor. During the transition period in 2011, the fair value of our derivatives increased by $157.7 million, of which $93.7 million was a mark-to-market gain and $64.0 million related to cash settlements. In comparison, the Predecessor recognized a $47.5 million loss in derivatives for the comparable period in 2010, comprised of a $235.0 million mark-to-market loss, offset by net cash settlements of $187.5 million.

Operating Expenses

Among the cost components of production expenses, the Predecessor had varying levels of control over lease operating expenses and workover costs on operated properties. Production and ad valorem taxes, in contrast, are directly related to changes in revenues.

Lease operating expenses. Lease operating expenses were $121.8 million, or $0.98 per Mcfe for the 2011 transition period ending December 21, 2011 and $124.4 million, or $0.96 per Mcfe for the comparable six month

 

59


Table of Contents

period in 2010. Considering the small decrease in production volume between the two periods, the per unit rates remained consistent.

Production and ad valorem taxes. Production and ad valorem taxes per unit of production were $0.49 per Mcfe for the period ending December 21, 2011, an increase on a per unit basis of approximately 20% from $0.41 per Mcfe for the six months ended December 31, 2010. This increase is directly related to both the approximately 13% increase in realized oil prices between the two periods, as well as the proportional increase in oil production as a component of total combined production.

Depreciation, depletion and amortization expense. DD&A expense was $342.6 million for the 2011 transitional period, an increase of $80.0 million, or approximately 30% from $262.6 million for the comparable period in 2010. On a per unit basis, DD&A expense was $2.77 per Mcfe and $2.03 per Mcfe for the same periods, respectively. The increase in the DD&A rate is primarily a result of the Predecessor’s shift towards focusing their capital program on oil rich resources which are more capital intensive in costs than related natural gas production.

General and administrative expenses. General and administrative expenses were $437.5 million, or $3.54 per Mcfe for the Predecessor’s transitional period of July 1, 2011 through December 21, 2011, a significant increase from the $57.5 million, or $0.44 per Mcfe recorded in general and administrative expenses for the six months ended December 31, 2010. The primary contributors to this increase are charges of $275.1 million related to the vesting and tendering of all stock appreciation rights of the Predecessor in contemplation of the Acquisition and $78.1 million of success bonuses paid to employees of the Predecessor upon completion of the Acquisition. Also impacting the increasing G&A rate was the decrease of $44.7 million of direct internal costs capitalized to the full cost pool for the 2011 period.

Interest expense. Interest cost of $39.2 million related primarily to the long-term debt incurred for the Predecessor for the transitional period in 2011, of which $27.0 million was capitalized. In comparison, $39.5 million in interest costs were incurred for the comparable six month period in 2010, of which $21.7 million was capitalized.

Loss on early extinguishment of debt. During the 2011 transition period, the Predecessor recorded loss of approximately $77.4 million related to the early payment of the existing long-term debt, including a $68.8 million make-whole premium, prior to the completion of the Acquisition.

Income tax provisions. The Predecessor recognized an income tax benefit of $85.2 million for the 2011 transitional period of July 1, 2011 through December 21, 2011, compared to the Predecessor’s income tax expense of $38.4 million for the comparable period in 2010, reflecting the change in pre-tax income (loss) between the periods. The effective income tax rate for the Predecessor’s 2011 transition period was 42%, reflecting state tax adjustments that were recognized during the period. The effective income tax rate for the comparable period in 2010 was 40%.

 

60


Table of Contents

Year Over Year Analysis

The following table sets forth selected operating data of the Predecessor for the fiscal years ending June 30, 2011, 2010 and 2009 (in thousands, except production data).

 

     Predecessor  
     Year Ended
June 30,  2011
    Year Ended
June 30, 2010
    Year Ended
June 30, 2009
 

Revenues

      

Natural gas and natural gas liquids sales

   $ 983,079      $ 995,563      $ 1,296,464   

Crude oil sales

     446,508        406,666        334,455   

Commodity derivatives

     (126,874     256,950        1,413,148   
  

 

 

   

 

 

   

 

 

 

Total Revenue

     1,302,713        1,659,179        3,044,067   

Operating expenses

      

Lease operating

     208,787        226,172        260,997   

Production and ad valorem taxes

     107,144        98,122        103,848   

Depreciation, depletion and amortization

     536,748        591,378        910,279   

Impairment

                   2,576,016   

General and administrative

     144,975        101,872        37,309   

Insurance proceeds

     (30,900              
  

 

 

   

 

 

   

 

 

 

Total operating expenses

     966,754        1,017,544        3,888,449   

Interest expense, net of capitalization

     (23,512     (38,560     (26,903

Other income

     10,220        3,425        10,933   

Income tax provision (benefit)

     116,979        205,293        (351,631
  

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 205,688      $ 401,207      $ (508,721
  

 

 

   

 

 

   

 

 

 

Production data:

      

Gas (Bcf) (a)

     229.2        226.0        241.8   

Oil (MMBbl)

     5.2        5.7        5.3   

Net Production (Bcfe) (b)

     260.5        260.1        273.8   

Production/day:

      

Gas mcf/d (a)

     628,071        619,085        662,578   

Oil B/d

     14,282        15,597        14,600   

Mcfe per day (b)

     713,764        712,668        750,178   

Price (before the effects of hedges):

      

Gas ($ per Mcf)

   $ 4.29      $ 4.41      $ 5.36   

Oil ($ per barrel)

     85.65        71.43        62.76   

Combined production ($ per Mcfe)

     5.49        5.39        5.96   

Price (after the effects of hedges):

      

Gas ($ per Mcf)

   $ 5.33      $ 5.98      $ 6.37   

Oil ($ per barrel)

     82.63        73.24        63.21   

Combined production ($ per Mcfe)

     6.35        6.80        6.86   

Average unit cost per combined production ($ per Mcfe):

      

Production costs:

      

Lease operating expense

   $ 0.80      $ 0.87      $ 0.95   

Production taxes

     0.41        0.38        0.38   
  

 

 

   

 

 

   

 

 

 

Total

   $ 1.21      $ 1.25      $ 1.33   
  

 

 

   

 

 

   

 

 

 

Depreciation, depletion and amortization

   $ 2.06      $ 2.27      $ 3.32   

General and administrative expenses, net

   $ 0.56      $ 0.39      $ 0.14   

 

(a) Natural gas volumes and prices include natural gas liquids for the periods presented.

 

61


Table of Contents
(b) Oil is converted to Mcfe using the industry standard conversion rate of one barrel of oil to six thousand cubic feet of natural gas.

Year Ended June 30, 2011 Compared to the Year Ended June 30, 2010

Oil and natural gas revenues. Oil and natural gas revenue was $1,429.6 million for the year ended June 30, 2011, an increase of $27.4 million, or approximately 2% from the $1,402.2 million of oil and natural gas revenues recognized for the year ended June 30, 2010. Specific factors affecting commodity sales include the following:

 

   

Total natural gas production was 229.2 Bcf for the year ended June 30, 2011, an increase of 3.2 Bcf, or approximately 1.5% from 226.0 Bcf for the year ended June 30, 2010. The small increase in natural gas volumes sold was primarily due to production from new wells which offset normal production declines and the decrease in production related to the Predecessor’s Permian and Offshore shelf divestitures.

 

   

Average realized natural gas price (excluding the effects of derivative activities) was $4.29 per Mcf for the year ended June 30, 2011, a decrease of approximately 3% from $4.41 per Mcf realized during the year ended June 30, 2010.

 

   

Total oil production was 5.2 MMBbl for the year ended June 30, 2011, a decrease of 0.5 MMBbl, or approximately 9% from 5.7 MMBbls for the year ended June 30, 2010. The decrease in volumes of oil sold is due to the divestitures of oil wells in both the Permian Basin and the Offshore shelf subsequent to June 30, 2010.

 

   

Average realized oil price (excluding the effects of derivative activities) was $85.65 per Bbl for the year ended June 30, 2011, an increase of approximately 20% from $71.43 per Bbl realized during the year ended June 30, 2010, reflecting increased market prices.

Gain/loss on derivatives not designated as hedges. The Predecessor’s earnings were affected by the changes in value of our derivatives portfolio, which could be volatile. To the extent the future commodity price outlook declined between measurement periods, the Predecessor recognized mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, the Predecessor recognized mark-to-market losses. For the year ended June 30, 2011, the fair value of the Predecessor’s derivatives decreased by $126.9 million, of which $350.3 million was a mark-to-market loss and $223.4 million related to cash settlements. In comparison, the Predecessor recognized a $257.0 million gain in derivatives for the comparable period in 2010, comprised of a $109.0 million mark-to-market loss, offset by net cash settlements of $366.0 million.

Operating Expenses. Among the cost components of production expenses, the Predecessor had varying levels of control over lease operating expenses and workover costs on operated properties, however, production and ad valorem taxes are directly related to changes in revenues.

Lease operating expenses. Lease operating expenses were $208.8 million for the year ended June 30, 2011 and $226.2 million for the year ended June 30, 2010, a decrease of $17.4 million, or approximately 8%. On a per unit basis, lease operating expenses were $0.80 per Mcfe and $0.87 per Mcfe for the same periods, respectively. The decrease in lease operating expenses reflects primarily an increase of $19.1 million in workover expenses.

Production and ad valorem taxes. Production taxes per unit of production were $0.41 per Mcfe during the year ended June 30, 2011, an increase of approximately 9% from $0.38 per Mcfe for the Predecessor during the year ended June 30, 2010. The increase in production taxes was directly related to the increase in realized oil prices, as well as the divestiture of oil wells in the Permian and Offshore shelf during fiscal year 2011. The Permian wells were subject to lower state taxes resulting in a higher per unit expense.

 

62


Table of Contents

Depreciation, depletion and amortization expense. DD&A expense was $536.7 million for the year ended June 30, 2011, a decrease of $54.6 million, or approximately 9% from $591.4 million for the year ended June 30, 2010. On a per unit basis, DD&A expense was $2.06 per Mcfe and $2.27 per Mcfe for the same periods, respectively. The decrease in the DD&A rate was primarily related to upward revisions in the estimates of remaining reserves due to increased pricing used to calculate existing reserves.

General and administrative expenses. G&A expenses were $145.0 million for the year ended June 30, 2011, an increase of $43.1 million, or approximately 42% from $101.9 million for the year ended June 30, 2010. On a per unit basis, G&A expenses were $0.56 per Mcfe and $0.39 per Mcfe for the same periods, respectively. This increase was driven primarily by increased employee-related expenses, including a $39.3 million increase in accrued stock appreciation rights, which were based on the Predecessor’s performance according to defined formulas, and a $17.6 million increase in salaries, wages and bonuses. During fiscal years 2011 and 2010, the Predecessor capitalized $79.5 million and $35.8 million of direct costs to the full cost pool.

Interest expense. Interest costs of $83.9 million in fiscal year 2011 as compared to $69.2 million in fiscal year 2010 reflects an increase in the amortization of debt issuance fees and increases in interest on direct bank loans in 2011, offset by an increase in the amount capitalized from $35.7 million in 2010 to $55.1 million in 2011.

Income tax provisions. We recognized income tax expense of $117.0 million for the year ended June 30, 2011, compared to $205.3 million for the year ended June 30, 2010, reflecting the change in pre-tax income between the periods. The Predecessor’s effective income tax rates for fiscal years 2011 and 2010 were 36% and 35%, respectively.

Discontinued operations. In 2010, the Predecessor recorded a loss from operations of discontinued businesses of $16.1 million related to its discontinued North Sea operations.

Year Ended June 30, 2010 Compared to the Year Ended June 30, 2009

Oil and natural gas revenues. Oil and natural gas revenue was $1,402.2 million for the year ended June 30, 2010, a decrease of $228.7 million, or approximately 14% from the $1,630.9 million of oil and natural gas revenues recorded for the fiscal year 2009. This decrease resulted primarily from decreases in volumes of natural gas sold, coupled with lower realized natural gas prices in fiscal year 2010 as compared to 2009. Decreases related to natural gas production were offset by increases in both the Predecessor’s crude oil production and the realized crude oil prices between the periods. Specific factors affecting commodity revenues include the following:

 

   

Total natural gas production was 226.0 Bcf for the year ended June 30, 2010, a decrease of 15.8 Bcf, or approximately 7% from 241.8 Bcf for the year ended June 30, 2009. Decreased production volumes were the result of reduced natural gas drilling activity for the Predecessor as natural gas prices fell.

 

   

Average realized natural gas price (excluding the effects of derivative activities) was $4.41 per Mcf during fiscal year 2010, a decrease of approximately 18% from $5.36 per Mcf realized during fiscal year 2009. The Predecessor’s historical natural gas prices were higher than the related NYMEX prices primarily due to the value of NGLs in the liquids-rich natural gas stream. The decrease in realized natural gas prices between the two periods reflects the broad deterioration in natural gas prices in the market during the period.

 

   

Total oil production was 5.7 MMBbl for the year ended June 30, 2010, an increase of 0.4 MMBbl, or approximately 8% from 5.3 MMBbl for the year ended June 30, 2009. The increase in oil production is primarily related to an increase in oil sales from three significant wells in the gulf coast.

 

   

Average realized oil price (excluding the effects of derivative activities) was $71.43 per Bbl during fiscal year 2010, an increase of approximately 14% from $62.76 per Bbl realized during fiscal year 2009.

 

63


Table of Contents

Gain on derivatives not designated as hedges. The Predecessor’s earnings were affected by the changes in value of their derivatives portfolio, which could be volatile. To the extent the future commodity price outlook declined between measurement periods, the Predecessor recognized mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, the Predecessor recognized mark-to-market losses. For the year ended June 30, 2010, the fair value of the Predecessor’s derivatives increased by $257.0 million, of which $109.0 million was a mark-to-market loss and $366.0 million related to cash settlements. In comparison, the Predecessor recognized a $1,413.1 million gain in derivatives for the comparable period in 2010, comprised of a $1,166.2 million mark-to-market gain, and net cash settlements of $246.9 million. The large mark-to-market gain recognized in 2009 was due to the Predecessor economically hedging a significant portion of natural gas production at prices that exceeded realized prices on physical sales when the natural gas market deteriorated during the last half of calendar year 2009.

Operating Expenses. Among the cost components of production expenses, the Predecessor had some control over lease operating expenses and workover costs on operated properties, but production and ad valorem taxes are directly related to commodity price changes, but can also be affected by credits received.

Lease operating expenses. Lease operating expenses were $226.2 million for the year ended June 30, 2010, which was a decrease of $34.8 million, or approximately 13% from $261.0 million for the year ended June 30, 2009. On a per unit basis, lease operating expenses were $0.87 per Mcfe and $0.95 per Mcfe for the same periods, respectively. The decrease per Mcfe rate is primarily due to $24.2 million in lower workover expenses attributable to the operational decision to delay workover activities as a result of decreasing gas prices.

Production and ad valorem taxes. Production and ad valorem taxes on a per unit of production basis remained flat between the periods, at $0.38 per Mcfe for both fiscal years 2010 and 2009. The $5.7 million decrease is directly attributable to the reduced drilling activity and lower gas prices in 2010.

Depreciation, depletion and amortization expense. DD&A expense was $591.4 million for the year ended June 30, 2010, a decrease of $318.9 million, or approximately 35% from $910.3 million for the year ended June 30, 2009. On a per unit basis, DD&A expense was $2.27 per Mcfe and $3.32 per Mcfe for the same periods, respectively. The majority of the decrease in DD&A expense was related to decreased production and lower DD&A rates on oil and natural gas properties. The DD&A rate decreased 32% on a per unit basis of production to $2.27 per Mcfe from $3.32 per Mcfe as a result of the impairment charge of $2,576.0 million recorded in June 2009 which reduced the Predecessor’s depletable base.

Impairment. At June 30, 2009, the Predecessor’s net book value for its oil and natural gas properties exceeded the ceiling amount and a provision to reduce the carrying value of oil and natural gas properties of $2,576.0 million ($1,571.4 million net of related deferred income taxes) was recorded. Also in fiscal year 2009, an impairment charge of $51.6 million was recorded as counterparties on two notes receivables defaulted on their respective obligations as a result of the economic downturn and deterioration of the real estate market.

General and administrative expenses. G&A expense increased $64.6 million for fiscal year 2010, to $101.9 million for the year ended June 30, 2010 from $37.3 million for the year ended June 30, 2009. On a per unit basis, G&A expenses were $0.39 per Mcfe and $0.14 per Mcfe for the same periods, respectively. The increase in G&A expenses was driven by an increase of $71.2 million in accrued stock appreciation rights, offset by contract cancellation fees of $20.2 million as compared to fiscal year 2009. Also contributing to the increase in G&A expense was a decrease in the amount of capitalized internal direct costs in 2010. Internal costs capitalized to the full cost pool were $41.1 million in fiscal year 2010 as compared to $50.3 million in fiscal year 2009.

Interest expense. The Predecessor incurred interest cost of $69.2 million for fiscal year 2010, an increase of $8.9 million from the $60.3 million incurred by the Predecessor during fiscal year 2009. The increase in interest cost is attributable to increases in the amortization of debt issuance fees, interest expense on direct bank loans and interest expense on notes payable to shareholders. Interest capitalized was $35.7 million and $28.5 million in fiscal years 2010 and 2009, respectively.

 

64


Table of Contents

Income tax provisions. We recognized income tax expense of $205.3 million for the year ended June 30, 2010, compared to an income tax benefit of $351.6 million for the year ended June 30, 2009, reflecting the change in pre-tax income (loss) for the period. The effective income tax rate for fiscal year 2010 was 35%, compared to a 39% tax rate in fiscal year 2009, reflecting state tax adjustments that were recognized during the period.

Discontinued operations. In fiscal year 2009, the Predecessor recognized a $51.7 million gain on disposal of its discontinued Kawka Canadian assets. This gain was offset by a $30.9 million loss on discontinued operations recorded during the year.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, financing under our RBL Revolver or proceeds from the disposition of assets or alternative financing sources.

Capital expenditures. Costs paid on oil and natural gas properties, including midstream assets and capitalized interest and capitalized internal costs, for the Successor period from inception (November 14, 2011) through December 31, 2011 was $2.6 million. The Predecessor paid $919.6 million during the 2011 transition period from July 1, 2011 though the date of the Acquisition of December 21, 2011 compared to $522.0 million during the comparable period in 2010. The increase in capital expenditures in 2011 was primarily due to the Predecessor’s shift towards oil and liquids-rich resources which are more capital intensive than similar natural gas developments. For the fiscal years ended June 30, 2011, 2010 and 2009, the Predecessor had capital expenditures of $1,587.8 million, $1,120.3 million and $1,518.6 million, respectively. We expect capital expenditures to total approximately $758.5 million for fiscal 2013.

We generally attempt to fund our non-acquisition expenditures with our available cash and cash flow as adjusted from time to time; however, we may also use our RBL Revolver, or other alternative financing sources, to fund such expenditures. The actual amount and timing of our expenditures may differ materially from our estimates as a result of, among other things, actual drilling results, the timing of expenditures by third parties on projects that we do not operate, the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions. In addition, under certain circumstances we would consider increasing or reallocating our capital spending plans.

Other than the customary purchase of leasehold acreage, we do not have a specific acquisition budget, since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of development, high-potential exploration and control of operations that will allow us to apply our operating expertise.

Acquisitions. The significant acquisitions of proved properties during the nine months ended September 30, 2012 related to a purchase of oil and natural gas properties for approximately $39.0 million during the second quarter of 2012.

The Successor made no material acquisitions or divestitures during the period from inception (November 14, 2011) through December 31, 2011, with the exception of the purchase of the Predecessor business described above. The Predecessor made various acquisitions of oil and natural gas properties and undeveloped leaseholds for a total purchase price of $28.7 million, for the period from July 1, 2011 to December 21, 2011.

During the years ended June 30, 2011 and 2010, the Predecessor completed several acquisitions of oil and natural gas properties and undeveloped leasehold for a total purchase price of approximately $63.8 million and

 

65


Table of Contents

$222.7 million, respectively. The most significant acquisition during the year ended June 30, 2010 was the acquisition of approximately $152.7 million of proved properties and $65.4 million of unproved properties located in Converse County, Wyoming, for a total purchase price of $218.1 million. The purchase closed on June 30, 2010 and significantly increased oil and natural gas holdings in the Powder River Basin.

Divestitures. In January 2011, the Predecessor sold substantially all of its oil and natural gas properties located in the Permian Basin for cash consideration of approximately $468.1 million.

Effective June 19, 2010, the Predecessor sold its interest in all remaining Offshore-shelf producing oil and natural gas properties in the Gulf of Mexico, for a net sales price of approximately $100.8 million.

In October 2012, we entered into an agreement to sell property located in Texas County, Oklahoma, for $20.6 million to Mid-Con Energy Properties LLC. The transaction closed on November 2, 2012.

In November and December 2012, we sold certain non-operating ownership interests in properties located in the Mid-Continent and Rockies regions for total consideration of $15.5 million, we sold $650.0 million of certain primarily non-operated Bakken producing and undeveloped properties in North Dakota to Continental Resources, Inc. and we sold an additional $30.0 million of certain primarily non-operated Bakken producing and undeveloped properties in North Dakota to another purchaser.

Contractual obligations. The table below summarizes the maturity dates of our contractual obligations at September 30, 2012 (in thousands).

 

    Payments Due by Period  
    Total     Less than  1
Year
    1-3 Years     3-5 Years     More than
5 Years
 

Long-term debt

         

Principal

  $ 4,595,000      $ —        $ —        $ 1,345,000      $ 3,250,000   

Interest

    2,265,557        284,835        598,275        608,426        774,021   

Drilling rig commitments

    123,500        94,500        29,000        —          —     

Derivatives

    103,758,399        15,787,935        65,271,629        22,698,835        —     

Preferred shares subject to mandatory redemption:

         

Preferred shares

    180,000        —          180,000        —          —     

Interest

    18,900        6,300        12,600        —          —     

Other operating leases

    14,565        4,097        6,485        1,342        2,641   

Marketing commitments

    67,792        13,167        17,520        19,362        17,743   

Other long-term liabilities, including current portion

    —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    111,023,713        16,190,834        66,115,509        24,672,965        4,044,405   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Excluded are liabilities associated with asset retirement obligations, which totaled $55.4 million as of September 30, 2012. The ultimate settlement and timing cannot be precisely determined in advance; however, we estimate that approximately 3% of this liability will be settled in the next five years.

Off-balance sheet arrangements. Currently, we have no off-balance sheet arrangements with third-parties or otherwise.

 

66


Table of Contents

Sources and Uses of Cash

Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011

The following table summarizes our net increase in cash and cash equivalents for the nine months ended September 30, 2012 and 2011 (in thousands):

 

    Successor     Predecessor  
    Nine Months
Ended
September 30, 2012
    Nine Months
Ended
September 30, 2011
 

Net cash provided (used) by:

     

Operating activities

  $ 426,788      $ 1,031,632   

Investing activities

    (1,072,100     (993,157

Financing activities

    631,355        (250,028
 

 

 

   

 

 

 

Net cash provided (used):

  $ (13,957   $ (211,553
 

 

 

   

 

 

 

Cash flow from operating activities. Net cash provided by operating activities decreased by $589.6 million to $426.8 million for the nine months ended September 30, 2012, as compared to $1,031.6 million in the nine months ended September 30, 2011, primarily due to decreased natural gas sales and increased costs described above. Our net cash provided by operating activities also included a reduction of $106.6 million and proceeds of $161.3 million for the nine months ended September 30, 2012 and 2011, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of cash.

Cash flow used in investing activities. During the nine months ended September 30, 2012 and 2011, we invested $1,072.1 million and $993.2 million, respectively, for capital expenditures, including capitalized interest and capitalized internal costs, on oil and natural gas properties, including midstream assets. Cash flows used in investing activities were higher during the nine months ended September 30, 2012 as compared to 2011, due primarily to the divestiture of the Permian Basin assets in 2011.

Cash flow from financing activities. During the nine months ended September 30, 2012 and 2011 we completed the following significant activities:

 

   

During the first quarter of 2012, we issued $2,250.0 million in aggregate principal amount of the notes. We used the proceeds to repay outstanding borrowings under our Bridge Facility.

 

   

During the second quarter of 2012, we issued 2.5 million shares of common stock to certain members of management for total consideration of $12.4 million.

 

   

During the third quarter 2012, we entered into a Second Lien Term Loan Agreement whereby we borrowed $1,000.0 million in aggregate principal due in 2018. We used the proceeds to repay a portion of the borrowings under our RBL Revolver. As a condition for entering into the Second Lien Term Loan Agreement, the borrowing base in our RBL Revolver was adjusted to $2,000.0 million.

Our RBL Revolver has a maturity date of April 25, 2016.

 

67


Table of Contents

2011 Transitional Period

The following table summarizes our net increase in cash and cash equivalents for the transitional period (in thousands):

 

     Successor      Predecessor  
     From Inception
(November  14, 2011)
through
December 31, 2011
     July 1, 2011
through
December 21, 2011
    Six Months
Ended
December 31, 2010
 

Net cash provided (used) by:

         

Operating activities

   $ (553,520    $ 410,554      $ 490,676   

Investing activities

     (6,897,175      (924,786     (356,179

Financing activities

     7,577,424         (95,000     92,872   
  

 

 

    

 

 

   

 

 

 

Net cash provided (used)

   $ 126,729       $ (609,232   $ 227,369   
  

 

 

    

 

 

   

 

 

 

Successor

Cash flow from operating activities. Net cash used of $553.5 million for Samson for the period from inception through the end of the fiscal year is primarily a result of net losses incurred as a result of transaction costs related to the Acquisition, as well as unfavorable changes in the working capital accounts, including the pay out of certain acquired accrued liabilities of the Predecessor, including $275.1 million related to the vesting and tendering of all stock appreciation rights of the Predecessor in contemplation of the Acquisition and $78.1 million related to success bonuses granted by the Predecessor upon the successful completion of the Acquisition.

Cash flow used in investing activities. The main component of the Successor’s $6,897.1 million used in investing activities was the purchase of the Predecessor business, net of cash acquired, of $6,894.0 million. Additionally, the Successor had $2.6 million in capital expenditures, including capitalized interest and capitalized internal costs, for oil and natural gas properties during the ten days following the Acquisition.

Cash flow from financing activities. During the period from inception through December 31, 2011, we completed the following significant activities:

 

   

We issued $2,250.0 million in aggregate principal amount of unsecured senior borrowings (“Bridge Facility”) to fund the Acquisition and related transaction costs. The Bridge Facility carried an interest rate of 8.0%. The Bridge Facility was subsequently paid off during the first quarter of 2012 through issuance of the notes.

 

   

We borrowed $1,345.0 million under the RBL Revolver. Our RBL Revolver matures in 2016 and provides for revolving loans, swingline loans and letters of credit up to $2,250.0 million. Borrowings under the RBL Revolver bear interest at floating rates based upon the interest rate option periodically selected by Samson. The weighted average interest rate was 2.04% at December 31, 2011.

 

   

As part of the Acquisition, common stock of the Successor was issued for total consideration of $4,145.0 million.

 

   

Total debt issuance costs of $162.6 million reduced the net cash provided by the borrowings under the Bridge Facility and the RBL Revolver discussed above.

Predecessor Transitional Period

Cash flow from operating activities. The decrease in cash provided by operating activities between the Predecessor’s 2011 transitional period and the comparable six months period in 2010 is due primarily to a net loss of $119.0 million in 2011 as compared to net income of $40.0 million in 2010. Additionally, the 2010 net income period included $238.2 million of non-cash unrealized derivative mark-to-market losses, while the 2011 net loss included unrealized mark-to-market gains of $85.2 million.

 

68


Table of Contents

Cash flow used in investing activities. During the Predecessor’s transitional period of July 1, 2011 through December 21, 2011, $919.6 million was invested in capital expenditures on oil and natural gas properties, including midstream assets. In contrast, capital expenditures in the comparable period in 2010 were lower at $483.4 million. Additionally, net cash flow used in investing activities for the Predecessor during 2010 were offset by $122.8 million in cash proceeds received from the divestiture of the Offshore shelf properties during July 2010.

Cash flow from financing activities. During the six months ended December 21, 2011 and the six months ended December 31, 2010, the Predecessor completed the following significant activities:

 

   

During the fourth quarter of 2011, the Predecessor borrowed $600.0 million under their existing revolver in order to repay outstanding notes payable.

 

   

Also during the fourth quarter of 2011, $695.0 million was used to repay long-term debt of the Predecessor prior to the completion of the Acquisition.

 

   

During the six months ended December 31, 2010, the Predecessor had proceeds from borrowings of $100.0 million, offset by $7.1 million paid in financing costs.

Year Over Year Analysis

The following table summarizes our net increase in cash and cash equivalents for the Predecessor’s fiscal years ending June 30, 2011, 2010 and 2009 (in thousands):

 

     Year Ended June 30,  
     2011     2010     2009  

Net cash provided (used) by:

      

Operating activities

   $ 1,426,645      $ 1,298,600      $ 1,129,735   

Investing activities

     (991,092     (1,055,739     (1,256,620

Financing activities

     (157,156     (20,138     (158,836
  

 

 

   

 

 

   

 

 

 

Net cash flows

   $ 278,397      $ 222,723      $ (285,721
  

 

 

   

 

 

   

 

 

 

Cash flow from operating activities. Net cash provided by operating activities for the year ended June 30, 2011 was $1,426.6 million as compared to $1,298.6 million for the year ended June 30, 2010, an increase of $128.0 million. The increase in net cash provided by operating activities for the year ended June 30, 2011 was primarily a result of a $241.2 million increase in the value of derivative instruments held, a $183.3 million increase in changes in assets and liabilities, and a $30.6 million increase in non-cash compensation expense, offset in part by the effect of a $179.4 million decrease in net income, a $82.9 million decrease in provision for deferred income taxes, and a $66.2 million decrease in depreciation, amortization and impairments.

Net cash provided by operating activities for the year ended June 30, 2010 was $1,298.6 million as compared to $1,129.7 million for the year ended June 30, 2009, an increase of $168.9 million. The increase in net cash provided by operating activities for the year ended June 30, 2010 was primarily a result of a $1,275.2 million increase in the value of derivative instruments held, a $873.0 million increase in net income, a $585.6 million increase in the provision for deferred income taxes, and a $343.8 million increase in the net change in assets and liabilities, offset in part by the effect of a $2,904.8 million decrease in depreciation, depletion, amortization and impairment and a $62.6 million decrease in non-cash compensation expense.

Cash flow used in investing activities. Net cash used in investing activities for the year ended June 30, 2011 totaled $991.1 million as compared to $1,055.7 million for the year ended June 30, 2010, a decrease of $64.6 million. The decrease in net cash used in investing activities for the year ended June 30, 2011 was primarily a result of a $501.5 million increase in proceeds from sales of oil and natural gas properties, primarily

 

69


Table of Contents

related to the Permian sale, and a $31.3 million decrease in purchases of other property and equipment, offset in part by the effect of a $498.8 million increase in acquisition and drilling expenditures for oil and natural gas properties.

Net cash used in investing activities for the year ended June 30, 2010 totaled $1,055.7 million as compared to $1,256.6 million for the year ended June 30, 2009, a decrease of $200.9 million. The decrease in net cash used in investing activities for the year ended June 30, 2010 was primarily a result of a $359.5 million decrease in acquisition and drilling expenditures for oil and natural gas properties, offset in part by a $149.0 million decrease in proceeds from the sale of Canadian assets in fiscal year 2009.

Cash flow from financing activities. Net cash used in financing activities for the year ended June 30, 2011 totaled $157.2 million as compared to $20.1 million for the year ended June 30, 2010, an increase of $137.1 million. The increase in net cash used in financing activities for the year ended June 30, 2011 was primarily a result of a $230.0 million increase in repayment of borrowings, offset in part by the effect of a $100.0 million increase in proceeds from borrowings.

Net cash used in financing activities for the year ended June 30, 2010 totaled $20.1 million as compared to $158.8 million for the year ended June 30, 2009, a decrease of $138.7 million. The decrease in net cash used in financing activities for the year ended June 30, 2010 was primarily a result of a $670.0 million decrease in repayment of borrowings, offset in part by the effect of a $545.0 million decrease in proceeds from issuance of long term debt and short term borrowings.

Liquidity. Our principal sources of short-term liquidity are cash on hand and available borrowing capacity under the RBL Revolver. At September 30, 2012, we had $112.8 million of cash on hand.

At September 30, 2012, the commitments under our RBL Revolver were $1,016.1 million, which provided us with approximately $983.9 million of available borrowing capacity. In December 2012, a redetermination of our borrowing base occurred related to the divesture of assets in the Bakken region. Our borrowing base was reduced to $1,780.0 million. There is no assurance that our borrowing base will not be reduced further, which could affect our liquidity.

Long-term debt increased by approximately $670.0 million during the nine months ended September 30, 2012. Proceeds were used primarily to fund our drilling and development program. Total capital expenditures related to our oil and natural gas properties, including midstream assets and capitalized interest and capitalized internal costs were $1,091.2 million during the nine months ended September 30, 2012. Long-term debt increased by $3,040.0 million during the six months ended December 31, 2011. The Predecessor repaid all existing long-term debt prior to the Acquisition. Upon the closing of the Acquisition, we entered into the RBL Revolver which provides for revolving borrowings up to $2,250.0 million. We borrowed $1,345.0 million under the RBL Revolver on the closing date of the Acquisition. Upon the closing of the Acquisition, we also entered into the Bridge Facility for $2,250.0 million to fund the Acquisition and related transaction costs.

Book Capitalization and Current Ratio

Our book capitalization at September 30, 2012 was $8,119.5 million, consisting of debt of $4,436.4 million (which includes $171.4 million book value of our redeemable preferred stock) and shareholders’ equity of $3,683.1 million. Our shareholders’ equity excludes puttable common stock with a book value of $12.4 million. Our debt to book capitalization was 54% and 47% at September 30, 2012 and December 31, 2011, respectively. Our ratio of current assets to current liabilities was approximately 2:3 at September 30, 2012 and December 31, 2011.

Inflation and Changes in Prices

Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the nine months ended September 30, 2012, we received an average of $83.50 per

 

70


Table of Contents

barrel of oil and $2.50 per Mcf of natural gas before consideration of commodity derivative contracts compared to $89.45 per barrel of oil and $4.46 per Mcf of natural gas in the nine months ended September 30, 2011. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004, and that has continued until recently, oil prices have increased significantly. The higher oil prices led to increased activity in the industry and, consequently, rising costs. These cost trends have put pressure not only on our operating costs, but also on capital costs. Although we have seen a decrease in commodity prices, the cost trends have not followed proportionally.

Critical Accounting Policies, Practices and Estimates

Our historical consolidated financial statements and related notes thereto contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates on historical experience and on assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be determined with certainty, and accordingly, these estimates may change as facts and circumstances change. Actual results may differ from the estimates used in the preparation of our consolidated financial statements.

Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes and (b) the impact of the estimates and assumptions on financial condition or operating performance is material. Estimates and assumptions that, in the opinion of management, are significant, include oil and natural gas reserves (including the associated future net cash flows from those proved reserves) used to compute depletion expense and the full cost ceiling limitation, amortization relating to oil and natural gas properties, costs withheld from amortization related to our oil and natural gas properties, asset retirement obligations, commodity derivatives, including fair value measurements used to record derivatives, employee stock-based compensation, asset impairments, business combinations, income taxes, and contingent liabilities.

Oil and natural gas properties. We utilize the full cost method of accounting for our oil and natural gas activities. Under the full cost method, all costs incurred in connection with the acquisition, exploration and development of oil and natural gas properties are capitalized and accumulated in cost centers on a country-by-country basis. Amounts capitalized include the costs of drilling and equipment for productive wells, dry hole costs, lease acquisition costs and delay rentals. Internal costs that are directly related to development and exploration activities such as salaries and employee benefits that are directly related to our oil and natural gas activities are also capitalized. The amortization base does not include any costs related to production, general corporate overhead or similar activities, which are expensed in the period incurred. Sales of proved and undeveloped oil and natural gas properties are accounted for as reductions of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves.

Proved oil and natural gas reserves. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and the full cost ceiling limitation. Proved oil and natural gas reserves are defined by the SEC as the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs based on the unweighted average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials and under period-end economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. The process of estimating quantities of proved

 

71


Table of Contents

reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in future revisions to the amount of our estimated proved reserves. Reserve estimates are updated at least annually and consider recent production levels and other technical information. All reserve information in this report is based on estimates prepared by our petroleum engineering staff. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that