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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 10-Q

 

(Mark One)

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

For the quarterly period ended: September 30, 2015 

OR

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

For the transition period from            to            

Commission file number: 333-173751

 

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code: 281-530-0991

 

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

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.   However, the registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant would have been required to file such reports) as if it were subject to such filing requirements.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)    Yes  ☒    No   ☐ 

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

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒ 

 

 

 

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Table of Contents 

 

 

 

 

 

 

 

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PART I — FINANCIAL INFORMATION

ITEM  1. Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)    

 

 

 

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

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

 

 

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

 

 

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

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

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1.  DESCRIPTION OF BUSINESS 

Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent energy company engaged in the acquisition, exploration, development, and production of onshore oil and natural gas properties located primarily in Oklahoma, Louisiana, and Texas. 

 

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Company has provided a discussion of significant accounting policies in Note 2 in its Annual Report on Form 10-K for the year ended December 31, 2014 (the “2014 Annual Report”). There have been no changes to the Company’s significant accounting policies since December 31, 2014.

Principles of Consolidation and Reporting

The consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2014, which were filed with the Securities and Exchange Commission in our 2014 Annual Report.

The consolidated financial statements included herein as of September 30, 2015, and for the three and nine months ended September 30, 2015 and 2014, are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. Certain reclassifications of prior period consolidated financial statements have been made to conform to current reporting practices. The Company reclassified $25.5 million of other receivables as of December 31, 2014 to receivables due from affiliate to conform to current reporting presentation on the consolidated balance sheets.  The $25.5 million was paid subsequent to year-end on January 2, 2015.  The reclassifications had no impact on net income (loss) or partners’ (deficit).  The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

Use of Estimates 

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers.  The update provides guidance concerning the recognition and measurement of revenue from contracts with customers.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In April 2015, the FASB proposed to delay the effective date one year, beginning in fiscal year 2018. The proposal will be subject to the FASB’s due process requirement, which includes a period for public comments.  We are currently evaluating the impact of adopting this standard on our consolidated financial statements.

In April 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a

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recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The guidance is effective for interim periods and annual periods beginning after December 15, 2015; however early adoption is permitted. The adoption of this guidance will not have a material impact on its financial position, results of operations or cash flows. 

In August 2015, the FASB issued ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30:  Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”), which confirms that line-of-credit arrangements are not in the scope of ASU 2015-03. ASU 2015-15 states that, for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are outstanding borrowings under the line-of-credit arrangement.

In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”), which eliminates the requirement for an acquirer in a business combination to restate prior period financial statements for measurement period adjustments. ASU 2015-16 requires that the cumulative impact of measurement period adjustments on current and prior periods be recognized in the reporting period in which the adjustment amount is determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

 3. ACQUISITION AND DIVESTITURES

Acquisition

On July 6, 2015, we acquired approximately 19,000 net acres of undeveloped leasehold interest in Kingfisher County, Oklahoma.  The consideration for the purchase was approximately $46.2 million and is subject to customary purchase price adjustments.  The effective date of the acquisition is April 1, 2015.  The purchase was funded with borrowings under our Sixth Amended and Restated Credit Agreement, dated as of May 13, 2010 (as amended, the “credit facility”). 

Divestitures

Eagleville Divestiture

On March 25, 2014, we closed the sale of certain of our properties located primarily in Karnes County, Texas to Memorial Production Operating LLC, comprising a portion of our Eagleville field (“Eagleville divestiture”).  The properties sold included a working interest in all of our producing wells as of the effective date of January 1, 2014.  We retained a net profits interest in these wells based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017.  Also included in the sale was a 30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014.  The Company received cash consideration of approximately $171 million after customary closing adjustments.  We estimate the proved developed and undeveloped reserves sold were approximately 7.5 MMBOE, and we retained proved reserves of approximately 7.7 MMBOE, 67% of which were proved undeveloped as of December 31, 2014.  We recorded a gain on sale from the Eagleville divestiture of $72.5 million during 2014, based on an allocation of basis between the properties sold and properties retained.

The portion of Eagleville field sold contributed approximately $6.6 million in pre-tax profit in the first quarter of 2014.

Alta Mesa Eagle, LLC Divestiture

 

On September 30, 2015, we closed the sale of all of the membership interests (the “Membership Interests”) in Alta Mesa Eagle, LLC (“AME”), our wholly owned subsidiary, to EnerVest Energy Institutional Fund XIV-A, L.P. and EnerVest Energy Institutional Fund XIV-WIC, L.P. (collectively, “EnerVest”) pursuant to a purchase and sale agreement (the “Sale Agreement”) entered into by us, AME and EnerVest on September 16, 2015 (the “Eagle Ford divestiture”).  AME owned our remaining non-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas.  In connection with the Eagle Ford divestiture, we disposed of all of our remaining interests in this area.  The effective date of the transaction (the “Effective Date”) is July 1, 2015.  

 

Pursuant to the Sale Agreement, the aggregate cash purchase price for the Membership Interests is $125 million subject to certain adjustments, consisting of $118 million (the “Base Purchase Price”), and additional contingent payments of approximately $7 million in the aggregate, payable to us by EnerVest by the 15th of each calendar month in which certain amounts owed to AME prior to the Effective Date have been received.  The Sale Agreement provides for customary purchase price adjustments to the Base Purchase Price based on the Effective Date. On October 1, 2015, the cash purchase price paid to us was $82.6 million, equal to 70% of the Base Purchase Price. On November 2, 2015, we received 35.4 million, which represents the remainder of our sales proceeds.  As of September 30, 2015, approximately $122.0 million of proceeds to be received from the sale, including $7.0 million of customary purchase price

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adjustments, was recorded in other receivables on the consolidated balance sheets.  Cash received was utilized to pay down borrowings under our credit facility.

 

As of the Effective Date, the estimated net proved reserves sold were approximately 7.8 MMBOE.    We recorded a preliminary gain on the sale of AME of approximately $66.3 million during the quarter ended September 30, 2015.  The sale of AME contributed approximately $1.4 million in pre-tax loss for the three months ended September 30, 2015 and $15.1 million in pre-tax profit for the three months ended September 30, 2014.  The sale of AME contributed approximately $0.4 million in pre-tax loss for the nine months ended September 30, 2015 and $112.8 million in pre-tax profit for the nine months ended September 30, 2014, which includes a $75.1 million gain on sale of assets for the first portion of the Eagleville divestiture as mentioned above.  Subsequent to the Eagle Ford divestiture, we no longer own any assets in the Eagle Ford.

Hilltop Divestiture 

On September 19, 2014, we sold our remaining interests in the Hilltop field for cash payment of $41.6 million, which was subsequently adjusted to $38.9 million for customary purchase price adjustments.  We recorded a gain on the sale of approximately $15.9 million.  The Hilltop interests contributed approximately $2.0 million and $7.2 million in net pre-tax income during the three months and nine months ended September 30, 2014, respectively.  

 

4. PROPERTY AND EQUIPMENT

 

Property and equipment consists of the following:

 

Suspended exploratory well costs

 

Our net changes in deferred exploratory well costs for the nine month period ended September 30, 2015, are presented below (unaudited):

 

 

 

 

The ending balance in deferred capitalized exploratory well costs includes the costs of four wells in one prospect.  At September 30, 2015, approximately $1.5 million of capitalized exploratory well costs had been capitalized for periods greater than one year.

 

 

 

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5. FAIR VALUE DISCLOSURES

We follow the guidance of ASC 820, “Fair Value Measurements and Disclosures,” in the estimation of fair values. ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least reliable. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.

The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the notes payable to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs.

Our senior notes are carried at historical cost, net of amortized discount; we estimate the fair value of the senior notes for disclosure purposes. We have estimated the fair value of our $450 million senior notes payable to be $237.4 million at September 30, 2015.  This estimation is based on the most recent trading values of the notes at or near the reporting dates, which is a Level 1 determination. See Note 8 for information on long-term debt.

We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (“NYMEX”) for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil and natural gas derivative contracts as Level 2.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and natural gas properties with a carrying amount of $295.7 million were written down to their fair value of $209.4 million, resulting in an impairment charge of $86.3 million for the nine months ended September 30, 2015.  Oil and natural gas properties with a carrying amount of $74.1 million were written down to their fair value of $46.2 million, resulting in an impairment charge of $27.9 million for the nine months ended September 30, 2014. Oil and natural gas properties with a carrying amount of $15.5 million were written down to their fair value of $6.6 million, resulting in an impairment charge of $8.9 million for the three months ended September 30, 2015.  For the three months ended September 30, 2014, oil and natural gas properties with a carrying amount of $13.8 million were written down to their fair value of $5.1 million, resulting in an impairment charge of $8.7 million. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

 

New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $1.7 million and $0.8 million in additions to asset retirement obligations measured at fair value during the nine months ended September 30, 2015 and 2014 respectively.  

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2015 and December 31, 2014, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:

 

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The amounts above are presented on a gross basis; presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. For additional information on derivative contracts, see Note 6.

 

6. DERIVATIVE FINANCIAL INSTRUMENTS

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil and natural gas. We also have utilized financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our crude oil and natural gas sales contracts. Substantially all of our hedging agreements are executed by affiliates of our lenders under the credit facility described in Note 8, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMbtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading or speculative purposes. 

We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statement of operations at each reporting date.

Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account. 

The following table summarizes the fair value (see Note 5 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815. 

 

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Fair Values of Derivative Contracts

 

 

 

 

 

 

 

 

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The following table summarizes the effect of our derivative instruments in the consolidated statements of operations:

 

 

 

 

Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, so long as we are not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility.

If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.

We had the following open derivative contracts for crude oil at September 30, 2015 (unaudited):  

 

OIL DERIVATIVE CONTRACTS

 

 

 

 

 

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We had the following open derivative contracts for natural gas at September 30, 2015 (unaudited):  

 

NATURAL GAS DERIVATIVE CONTRACTS

 

 

 

In those instances where contracts are identical as to time period, volume and strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either the NYMEX or Brent ICE indices or may reflect a mix of positions settling on these two indices. 

 

7. ASSET RETIREMENT OBLIGATIONS

A summary of the changes in asset retirement obligations is included in the table below:

 

 

 

The total revisions include $0.6 million related to reduction to oil and natural gas properties.

 

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8. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER

Long-term debt and notes payable to founder consists of the following:

 

 

 

Credit Facility.  On June 2, 2015, we entered into an Agreement and Amendment No. 11 (the “Eleventh Amendment”) to the credit facility, with Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto.  The Eleventh Amendment, among other things, (i) redetermined and decreased the borrowing base from $375 million to $300 million, and (ii) extended the maturity date of the credit facility to October 13, 2017. The principal amount is payable at maturity. On September 30, 2015, we entered into an Agreement and Amendment No. 12 (the “Twelfth Amendment”) to amend the credit facility  to permit the Eagle Ford divesture as described in Note 3 and to release AME as a guarantor from the credit facility.  As a result of the Eagle Ford divestiture, the borrowing base decreased from $300 million to $255 million.  Net proceeds from the Eagle Ford divestiture were used to pay down the credit facility.  The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves.  The credit facility borrowing base is redetermined periodically semi-annually in May and November. The credit facility bears interest at LIBOR plus applicable margins between 2.00% and 2.75% or a “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The weighted average rate on outstanding borrowings was 2.85% as of September 30, 2015 and 2.89% as of December 31, 2014.  The letters of credit outstanding as of September 30, 2015 were $65,000.

 

The credit facility contains customary covenants including, among others, defined financial covenants, including minimum working capital levels (the ratio of current assets plus the unused borrowing base, to current liabilities, excluding assets and liabilities related to derivative contracts) of 1.0 to 1.0, minimum coverage of interest expense of 3.0 to 1.0, and maximum leverage of 4.00 to 1.00.  The interest coverage and leverage ratios refer to the ratio of earnings before interest, taxes, depreciation, depletion, amortization, and exploration expense (“EBITDAX”, as defined more specifically in the credit agreement) to interest expense and to total debt (as defined), respectively. Financial ratios are calculated quarterly using EBITDAX for the most recent twelve months.  As of September 30, 2015, we were in compliance with all covenants of the credit facility.

 

Senior Secured Term Loan.  On June 2, 2015, we entered into a second lien Senior Secured Term Loan Agreement (the “Term Loan Facility”) with Morgan Stanley Energy Capital Inc., as administrative agent, and the lenders party thereto, pursuant to which we borrowed $125 million.  The Term Loan Facility includes an accordion feature which allows us to borrow up to an additional $50 million of additional term loans under the Term Loan Facility within one year following the closing, subject to certain conditions.  The net proceeds of approximately $121 million from the Term Loan Facility, after payment of transaction-related fees and expenses, were used to pay down our outstanding amounts under our existing credit facility.  The Term Loan Facility matures on April 15, 2018. The principal amount is payable at maturity. 

 

Borrowings under the Term Loan Facility bear interest at adjusted LIBOR plus 8%. The covenants in the Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) current assets to current liabilities of at least 1.0 to 1.0, (ii) debt to EBITDAX of no more than 4.5 to 1.0, (iii) PV-9 of total proved reserves to total secured debt of at least 1.5 to 1.0, and (iv) EBITDAX to interest expense of at least 2.5 to 1.0.  Obligations under the Term Loan Facility are guaranteed by certain of the Company’s subsidiaries and affiliates and is secured by second priority liens on substantially all of our and our subsidiaries assets that serve as collateral under the credit facility.  As of September 30, 2015, we were in compliance with all covenants of the Term Loan Facility.

 

We have the option to prepay all or a portion of the Term Loan Facility at any time. The Term Loan Facility is subject to mandatory prepayments of 75% of the net cash proceeds from asset sales, subject to a limited right to reinvest proceeds in capital expenditures, or an initial public offering. Such prepayments are subject to a premium of between 3% declining to 1% prior to the maturity date, and, if made prior to the first anniversary of the closing date, are also subject to a make whole premium to ensure that the lenders receive the total amount of interest that would have been paid from the date of prepayment to such first anniversary.

Senior Notes. We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective rate of 9.7825%.  Interest is payable semi-annually each April 15th and October 15th.  The senior notes are unsecured and are our general obligations, and effectively rank junior to any of our existing or future secured indebtedness, which

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includes the credit facility and the Term Loan Facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries. The balance is presented net of unamortized discount of $1.5 million and $1.9 million at September 30, 2015 and December 31, 2014, respectively.

The senior notes contain an optional redemption provision that began on October 15, 2015 allowing us to retire the principal outstanding, in whole or in part, at 102.406%.  Additional optional redemption provisions allow for retirement at 100.0% beginning on October 15, 2016.    

Notes Payable to Founder. We have notes payable to our founder that bear simple interest at 10% with a balance of $25.4 million and $24.5 million at September 30, 2015 and December 31, 2014, respectively.  The maturity date was extended from December 31, 2018 to December 31, 2021 on March 25, 2014.  Interest and principal are payable at maturity. The notes are convertible into shares of common stock of our Class B partner, High Mesa, Inc. (“High Mesa”), upon certain conditions in the event of an initial public offering. 

These founder notes are unsecured and subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 12, the founder notes were amended and restated to subordinate them to the paid in kind (“PIK”) notes of our Class B partner.  The founder notes were also subordinated to the rights of the holders of Class B units to receive distributions under our amended partnership agreement and subordinated to the rights of the holders of Series B preferred stock to receive payments. 

Interest on the notes payable to our founder amounted to $0.9  million for each of the nine months ended September 30, 2015 and 2014 and $0.3 million for each of the three months ended September 30, 2015 and 2014. Such amounts have been added to the balance of the founder notes.

9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The following provides the detail of accounts payable and accrued liabilities:

 

 

 

 

 

10. COMMITMENTS AND CONTINGENCIES

Contingencies

Environmental claims: Various landowners have sued us in lawsuits concerning several fields in which we have or historically had operations in Louisiana.  The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our consolidated financial statements at September 30, 2015.

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any.  We have accrued a liability for soil contamination in Florida of $1.2 million and $1.1 million at September 30, 2015 and December 31, 2014, respectively, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.  

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Title/lease disputes: Title and lease disputes may arise in the normal course of our operations. These disputes are usually small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made.

Litigation: On April 13, 2005, Henry Sarpy and several other plaintiffs filed a petition against Exxon, Extex, The Meridian Resource Company (“TMRC” our wholly-owned subsidiary), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish.  Petitioners claim they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located.  Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon.  The property was originally owned by Exxon and was sold to TMRC.  TMRC subsequently sold the property to Extex. We have been defending this ongoing case and investigating the scope of the Plaintiffs’ alleged damage.  On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter.  On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs’ and Exxon.  On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement.    As of September 30, 2015, we have accrued approximately $5.0 million ($1.1 million in current liabilities and $3.9 million in other long-term liabilities) as the outcome of the litigation was deemed probable and estimable.      

Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business for which the outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

Performance appreciation rights:    In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014.  The Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company.  Under the Plan, participants are granted Performance Appreciation Rights (“PARs”) with a stipulated initial value.  The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the initial stipulated value and the designated value of the PAR on the payment valuation date.  The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally intended to be either a recapitalization or an initial public offering of Company equity) or as selected by the participant, but no earlier than five years from the end of the year of the grant.  Both the initial designated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors. In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event.  After any payment valuation date, regardless of payment or none, vested PARs expire. During the first nine months of 2015, 5,000 new PARs were granted and 27,500 PARs were terminated, resulting in 249,000 outstanding PARs. We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan. We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote.  Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at September 30, 2015 or December 31, 2014.

11. SIGNIFICANT RISKS AND UNCERTAINTIES

Our business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas were highly volatile in 2014 and declined dramatically in the second half of 2014 and remain depressed as of September 30, 2015.  Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved reserves.  Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. As a result of the depressed commodity prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2015 from 2014 levels.  Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.  We mitigate some of this vulnerability by entering into oil and natural gas price derivative contracts.  See Note 6.

12. PARTNERS’ DEFICIT

 

Management and Control:  Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in the Partnership Agreement.  Our partnership agreement provides for two classes of limited partners.  Class A partners include our founder and other parties.  Our Class B partner is High Mesa, Inc.  The Class B limited partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture.

Distribution and Income Allocation: In connection with the recapitalization on March 25, 2014, our partnership agreement was amended and restated to provide, among other things, that all distributions under the partnership agreement shall first be made to

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holders of Class B Units, until certain provisions are met.  After such provisions are met, distributions shall then be made to holders of Class A and Class B Units pursuant to the distribution formulas set forth in the amended partnership agreement. 

The Class B Partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility, Term Loan Facility, and our senior notes.

Distribution of net cash flow from a Liquidity Event is distributed to the Class A and Class B Partners according to a variable formula as defined in the partnership agreement. A “Liquidity Event” is any event in which we receive cash proceeds outside the ordinary course of our business. The Class B Partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.

During the third quarter of 2015, our Partnership agreement was amended and restated (“Third Amended and Restated Limited Partnership Agreement”).  In connection with the amendment, our Class B Partner contributed $20 million to us, which we used to pay down amounts owed under the credit facility.

For the nine months ended September 30, 2015, we made distributions of approximately $3.8 million.    

 

13. SUBSIDIARY GUARANTORS

All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes, our credit facility and our Term Loan Facility. Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. The parent company, Alta Mesa Holdings, LP, has no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several.  Those subsidiaries which are not wholly owned and are not guarantors are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to the parent company.

 

14.  SUBSEQUENT EVENT 

In connection with the regular redetermination of our borrowing base in November 2015, we received notice that our borrowing base under the credit facility increased from $255 million to $300 million.

 

 

 

 

 

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

The following discussion and analysis should be read in conjunction with the financial statements and related notes included elsewhere in this report. In addition, such analysis should be read in conjunction with the financial statements and the related notes included in our Annual Report on Form 10-K for the year ended December 31, 2014 (“2014 Form 10-K”).  The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below in “Cautionary Statement Regarding Forward-Looking Statements,” and in our 2014 Form 10-K, particularly in the section titled “Risk Factors,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.   

Overview

We have been engaged in onshore oil and natural gas acquisition, exploitation, exploration and production since 1987.   We operate in one industry segment, oil and natural gas exploration and development, within one geographical segment, the United States.  Currently, we are focused on our development efforts of our high quality core properties in the Sooner Trend field of the Anadarko Basin in Oklahoma, and in our Weeks Island Area in South Louisiana.  We maintain operational control of virtually all of our assets. 

The amount of cash we generate from our operations will fluctuate based on, among other things:

•the prices at which we will sell our production;

•the amount of oil and natural gas we produce; and

•the level of our operating and administrative costs.

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to hedging and other price protection contracts, and we intend to enter into such transactions in the future to reduce the effect of low oil and natural gas prices on our cash flows.

Substantially all of our oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect our proportionate interest in such activities. Inflation has not had a material impact on our results of operations and we do not expect inflation to have a material impact on the results of our operations in the future.

2015 Third Quarter Highlights

 

Acquisitions

On July 6, 2015, we acquired approximately 19,000 net acres of undeveloped leasehold interest in Kingfisher County, Oklahoma.  The consideration for the purchase was approximately $46.2 million and is subject to customary purchase price adjustments.  The effective date of the acquisition is April 1, 2015.  The purchase was funded with borrowings under our credit facility. 

 

Divestitures

On September 30, 2015, we closed the sale of all of the membership interests (the “Membership Interests”) in Alta Mesa Eagle, LLC (“AME”), our wholly owned subsidiary, to EnerVest Energy Institutional Fund XIV-A, L.P. and EnerVest Energy Institutional Fund XIV-WIC, L.P. (collectively, “EnerVest”) pursuant to a purchase and sale agreement (the “Sale Agreement”) entered into by us, AME and EnerVest on September 16, 2015 (the “Eagle Ford divestiture”).  AME owned our remaining non-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas.  In connection with the Eagle Ford divestiture, we disposed of all of our remaining interests in this area.  The effective date of the transaction (the “Effective Date”) is July 1, 2015.

 

Pursuant to the Sale Agreement, the aggregate cash purchase price for the Membership Interests is $125 million subject to certain adjustments, consisting of $118 million (the “Base Purchase Price”), and additional contingent payments of approximately $7 million in the aggregate, payable to us by EnerVest by the 15th of each calendar month in which certain amounts owed to AME prior to the Effective Date have been received.  The Sale Agreement provides for customary purchase price adjustments to the Base Purchase Price based on the Effective Date. On October 1, 2015, the cash purchase price paid to us was $82.6 million, equal to 70% of the Base Purchase Price. On November 2, 2015, we received 35.4 million, which represents the remainder of our sales proceeds.  As of September 30, 2015, approximately $122.0 million of proceeds to be received from the sale, including $7.0 million of customary purchase price adjustments, was recorded in other receivables on the consolidated balance sheets.  Cash received was utilized to pay down borrowings under our credit facility.  Subsequent to the Eagle Ford divestiture, we no longer own any assets in Eagle Ford.

Throughout this report, revenue and operating data include portion of our Eagleville assets that were sold in the third quarter of 2015 through the closing date of September 30, 2015.  The Eagleville field contributed approximately $5.5 million in revenues, $3.6

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million in total operating expense and production taxes, and $3.2 million in depreciation, depletion, and amortization for the three months ended September 30, 2015.  Production from Eagleville for the third quarter of 2015 was 166 MBOE.  The Eagleville field contributed approximately $22.6 million in revenues, $5.3 million in total operating expense and production taxes, and $12.2 million in depreciation, depletion, and amortization for the nine months ended September 30, 2015.  Production from Eagleville for the nine months ended September 30, 2015 was 583 MBOE.

Outlook

Our revenue, profitability and future growth depend on many factors, particularly the prices of oil and natural gas, which are beyond our control.  Factors affecting the commodity prices include worldwide economic conditions, including the European credit crisis; geopolitical activities, including developments in the Middle East, Ukraine, and South America; worldwide supply and demand; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets.  Importantly, oil prices have declined significantly over the last year.  Sustained low oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, the value of our proved reserves, the amount of oil and natural gas that we are economically able to produce and our ability to finance operations, including the amount of our borrowing base under our credit facility.

Oil and natural gas prices historically have been volatile and may fluctuate widely in the future.  During the last 12 month period ended September 30, 2015, NYMEX West Texas Intermediate (“NYMEX WTI”) oil prices ranged from a high of $92.96 per Bbl in October 2014 to a low of $37.75 per Bbl in August 2015.  During the third quarter of 2015, NYMEX WTI prices averaged approximately $46.43 per Bbl.  We received an average price of $45.83 per Bbl for the third quarter of 2015 before the effects of hedging.  NYMEX Henry Hub natural gas prices (“NYMEX HH”) have also been volatile and ranged from a high of $4.54 per MMBtu in November 2014 to a low of $2.44 in April 2015. We received an average price of $2.57 per Mcf for natural gas in the third quarter of 2015 before the effects of hedging. The duration and magnitude of changes in oil and natural gas prices cannot be predicted.

Low oil and natural gas prices have impacted our earnings by necessitating impairment write-downs to some of our oil and natural gas properties, either directly by decreasing the market values of the properties, or indirectly, by lowering rates of return on oil and natural gas development projects and increasing the chance of impairment write-downs.  We recorded non-cash impairment expenses of $74.9 million during the year ended December 31, 2014.  For the first nine months of 2015, oil and natural gas prices have remained low.  Impairment expense was $86.3 million for the nine months ended September 30, 2015.  Further declines in oil and/or natural gas prices may result in additional impairments.

Sustained low oil or natural gas prices may require us to further revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. As a result of the low commodity prices and in order to preserve our liquidity, we reduced our budgeted capital expenditures for 2015 from 2014 levels.  Low prices may also reduce our cash available for distribution and for servicing our indebtedness.

Our derivative contracts are reported at fair value on our consolidated balance sheets and are sensitive to changes in the price of oil and natural gas. Changes in these derivative assets and liabilities are reported in our consolidated statement of operations as gain / loss from derivative contracts, which include either the non-cash increase or decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. In the first nine months of 2015, we recognized a net gain on our derivative contracts of $83.6 million, which includes $77.6 million in cash settlements received on derivative contracts. The objective of our hedging program is that, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil and natural gas revenues will produce relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and we expect these gains and losses to continue to reflect changes in oil and natural gas prices.

Currently, we have hedged approximately 79% of our forecasted production of proved developed producing reserves through 2019 at weighted average annual floor prices ranging from $62.50 per Bbl to $72.27 per Bbl for oil and $2.91 per MMbtu to $4.50 per MMbtu for natural gas.  If oil and/or natural gas prices decline for an extended period of time, we may be unable to replace expiring hedge contracts or enter new contracts for additional oil and natural gas production at favorable prices. 

The primary factors affecting our production rates are natural production declines, the effectiveness and efficiency of our production operations, the success of our drilling, our inventory of drilling locations, and capital availability.  We attempt to offset natural production declines primarily through drilling wells to produce our undeveloped reserves, improving existing completions, recompleting wells into other productive formation, and employing other enhanced recovery methods. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.

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Operations Update

Sooner Trend.    Our assets in the Sooner Trend of Oklahoma are large, contiguous acreage blocks with multiple productive zones at depths generally between 4,000 feet and 8,000 feet.  Our focus is the continued implementation of a multi-year, multi-rig program to develop several pay zones with horizontal drilling and multi-stage hydraulic fracturing.  In July 2015, we acquired acreage contiguous with our legacy assets to position us for expanded horizontal development of stacked pays.  In the third quarter of 2015, we completed seven horizontal wells in the Osage and Meramec formations in Sooner Trend. We had nineteen horizontal wells in progress as of the end of the third quarter of 2015, six of which were completed subsequent to quarter end.  Seven of the wells in progress for the third quarter of 2015 were non-operated.

As of September 30, 2015, we had two drilling rigs operating in Sooner Trend for horizontal development.  We plan to maintain at least two drilling rigs for the remainder of 2015, targeting the Osage and Meramec with horizontal drilling.  We expect to continue to participate in other horizontal wells as a non-operator, primarily targeting the Meramec, Osage, and Oswego Lime.    

Production from our Sooner Trend properties in the third quarter of 2015 was approximately 9,500 BOE/Day net to our interest, 76% oil and natural gas liquids, as compared to approximately 5,300 BOE/Day, 80% oil and natural gas liquids, for the third quarter of 2014.

Weeks Island Area.  The Weeks Island Area, located in Iberia and St. Mary Parish, Louisiana, contains some of our largest proved developed reserves and consists of the Weeks Island and Cote Blanche Island fields. 

Weeks Island field, located in Iberia Parish, Louisiana, is a historically-prolific oil field with 55 potential pay zones that are structurally and stratigraphically trapped around a piercement salt dome.

Cote Blanche Island field is located near to Weeks Island in St. Mary Parish, and has over 30 potential pay zones trapped around other salt dome structure.  Both fields have similar geology and we utilizing the same geologic interpretation methods and engineering development techniques at Cote Blanche that are used at Weeks Island to increase reserves and production.  

Production from Weeks Island area in the third quarter of 2015 was approximately 4,700 BOE/Day, net to our interest, 86% oil, as compared to 6,000 BOE/Day, 82% oil, for the third quarter of 2014.  Production from the Weeks Island area has remained above 4,000 BOE/Day, net to our interest, since November 2013.  

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Results of Operations: Three Months Ended September 30, 2015 v. Three Months Ended September 30, 2014

 

 

 

 

 

 

(1)We do not utilize hedges for natural gas liquids.

 

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Revenues

Oil revenues for the three months ended September 30, 2015 decreased $54.0 million, or 52%,  to $50.2 million from $104.2 million for the corresponding period in 2014. The decrease in revenue was primarily attributable to a decrease in average price partially offset by an increase in production volumes. The average price of oil exclusive of settlements of derivative contracts decreased $52.17 per Bbl or 53% in the third quarter of 2015 compared to the third quarter of 2014, resulting in a decrease in oil revenues of approximately $57.2 million.  The overall price including settlements of derivative contracts decreased 34% from $96.99 per Bbl in the third quarter of 2014 to $63.78 per Bbl in the third quarter of 2015.    This decrease is partially offset by increased production resulting in an increase of $3.2 million in oil revenues.  The increase in production is primarily due to Sooner Trend production that increased by 226 MBbls, from 302 MBbls in the third quarter of 2014 to 528 MBbls in the corresponding period of 2015. The increase in production from Sooner Trend was partially offset by decreases in production to Weeks Island area of 83 MBbls and Eagleville field of 101 MBbls in the third quarter of 2015 as compared to corresponding period of 2014.

Natural gas revenues for the three months ended September 30, 2015 decreased $7.8 million, or 48%, to $8.4 million from $16.2 million for the same period in 2014. The decrease in natural gas revenue was attributable to both a decrease in price and production during the third quarter of 2015. The average price of natural gas exclusive of settlements of derivative contracts decreased 39% in the third quarter of 2015, resulting in a decrease in natural gas revenues of approximately $5.3 million.  The overall price including settlements of derivative contracts decreased 48% from $4.62 per Mcf in the third quarter of 2014 to $2.41 per Mcf in the third quarter of 2015.  An approximate $2.5 million decrease in natural gas revenues was due to a decrease in production of 0.6 BCF, or 16%. This decline is primarily due to an emphasis on liquids-rich assets in our portfolio of assets. 

Natural gas liquids revenues decreased $2.3 million, or 47%, during the third quarter of 2015 to $2.5 million from $4.8 million in the same period in 2014. The decrease in natural gas liquids revenue was attributable to a lower average price during the third quarter of 2015, partially offset by increased production volumes.  A decrease in our average price of 60%, from $33.78 per Bbl in the third quarter of 2014 to $13.42 per Bbl in the third quarter of 2015 was partially offset by a 32% increase in volumes from 142 MBbls to 188 MBbls.  The increase in volume is primarily due to an increase in production of 54 MBbls in the third quarter of 2015 in our Sooner Trend field in Oklahoma offset by the decline in production volume of 6 MBbls by Eagleville field. 

Other revenues decreased $0.3 million during the three months ended September 30, 2015 as compared to the three months ended September 30, 2014.  The revenue is related to pipeline and processing fees from our East Texas properties.

Gain on sale of assets was $66.4 million for the third quarter of 2015 as compared to a gain of $18.6 million for the third quarter of 2014. The third quarter 2015 gain was due to the sale of AME, which owned our remaining interests in the Eagleville field, and the third quarter 2014 was due to the sale of our remaining interests in the Hilltop field.    

Gain— oil and natural gas derivative contracts was a gain of $72.0 million during the three months ended September 30, 2015 as compared to a gain of $39.9 million during the same period in 2014. The change from period to period is due to the drop in oil and natural gas prices and changes in our derivative contracts during these periods. 

Expenses

Lease and plant operating expense increased $0.9 million or 5% in the third quarter of 2015 as compared to the third quarter of 2014, to $19.3 million from $18.4 million, primarily due to an increase in field services of $3.1 million, partially offset by a decrease in marketing/gathering and repairs and maintenance of $2.7 million.  On a per unit basis, lease and plant operating expenses were $10.58 per BOE and $9.97 per BOE for the third quarters of 2015 and 2014, respectively.    

Production and ad valorem taxes decreased $4.0 million, or 48%, to $4.4 million for the third quarter of 2015, as compared to $8.4 million for the third quarter of 2014.  Production taxes decreased approximately $3.9 million during the third quarter of 2015, to $3.5 million from $7.4 million for the corresponding period in 2014, primarily due to the decline in oil and gas revenue.  Ad valorem taxes remained flat for the third quarter of 2015 from the corresponding period of 2014. 

Workover expense decreased $1.4 million during the third quarter of 2015, as compared to the third quarter of 2014. This expense varies depending on activities in the field and is attributable to many different properties.

Exploration expense includes dry hole costs and the costs of our geology department, costs of geological and geophysical data, expired leases, plug and abandonment expenditures, and delay rentals. Exploration expense decreased from $15.8 million for the third quarter of 2014 to $6.8 million for the third quarter of 2015, primarily due to a decrease in geologic and geophysical (G&G) seismic expense,  plug and abandonment expenditures, and dry hole costs in the third quarter of 2015 as compared to the third quarter of 2014.  Third quarter of 2015 includes dry hole expense of $3.6 million and lease expense and expired leasehold of $1.5 million.

Depreciation, depletion and amortization decreased $7.0 million to $32.9 million for the third quarter of 2015 as compared to $39.9 million for the third quarter of 2014. On a per unit basis, this expense decreased from $21.56 per BOE in the third quarter of

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2014 to $18.03 per BOE in the third quarter of 2015. Depreciation, depletion, and amortization is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense increased from $8.7 million in the third quarter of 2014 to $8.9 million in the third quarter of 2015. This expense varies with the results of drilling, as well as with price declines and other factors that may render some fields uneconomic, resulting in impairment.  Impairment expense in the third quarter of 2015 included a write-down of natural gas fields in South Louisiana and South Texas.  Impairment expense in the third quarter of 2014 included a write-down of a natural gas field in South Louisiana.

Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $0.6 million for the third quarter of 2015 and $0.4 million for the corresponding period in 2014.

General and administrative expense decreased $1.4 million for the third quarter of 2015 to $15.8 million from $17.2 million for the third quarter of 2014. The decrease is principally due to deferred compensation of $1.6 million recorded in the third quarter of 2014, a decrease in salary and benefits of $1.0 million primarily due to performance bonus accrual recorded in the third quarter of 2014 and a decrease in legal fees of $0.5 million, partially offset by Eagleville closing fees of $1.6 million and an increase in litigation settlement expense of $.3 million.  On a per unit basis, general and administrative expenses were $8.64 per BOE and $9.32 per BOE for the third quarters of 2015 and 2014, respectively.

Interest expense, net increased from $13.7 million for the third quarter of 2014 to $16.7 million for the third quarter of 2015.  The increase is primarily due to interest incurred on the second lien senior secured term loan of $2.7 million that we entered into during the second quarter of 2015, and increased interest on our credit facility of $0.3 million due to a higher average outstanding balance. 

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Results of Operations: Nine Months Ended September  30, 2015 v. Nine Months Ended September 30, 2014

 

 

 

(1)We do not utilize hedges for natural gas liquids.

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Revenues

Oil revenues for the nine months ended September 30, 2015 decreased $116.7 million, or 42%, to $159.8 million from $276.5 million for the corresponding period in 2014. The decrease in revenue was attributable to a lower average price partially offset by increased production volumes. The average price of oil exclusive of settlements of derivative contracts decreased 50% in the first nine months of 2015, resulting in a decrease in oil revenues of approximately $161.5 million.  The overall price, including settlements of derivative contracts, decreased 31% from $97.10 per Bbl in the first nine months of 2014 to $67.20 per Bbl in the first nine months of 2015.  

Oil production for the first nine months of 2015 increased 449 MBbls, or 16%, resulting in an increase in oil revenue of approximately $44.8 million. This increase is primarily due to an increase in production from the Sooner Trend field in Oklahoma partially offset by a decrease in production from the Weeks Island Area and Eagleville field.  Oil production from the Sooner Trend field increased by 736 MBbls, from 722 MBbls in the first nine months of 2014 to 1,458 MBbls in the corresponding period of 2015.  Weeks Island Area oil production decreased 66 MBbls, from 1,155 MBbls in the first nine months of 2014 to 1,089 MBbls for the first nine months of 2015.  We sold a portion of our interest in the Eagleville field in the first quarter of 2014 and the remaining portion of our interest in the Eagleville field in the third quarter of 2015.  Eagleville field oil production decreased 157 MBbls, from 588 MBbls in the first nine months of 2014, to 431 MBbls in the first nine months of 2015. 

Natural gas revenues for the nine months ended September 30, 2015 decreased $27.9 million, or 53%, to $24.8 million from $52.7 million for the same period in 2014. The decrease in natural gas revenue was attributable to a decrease in price and production during the first nine months of 2015.  The average price of natural gas exclusive of settlements of derivative contracts decreased 41% in the first nine months of 2015, resulting in a decrease in natural gas revenues of approximately $17.1 million.  The overall price, including settlements of derivative contracts, increased 2% from $4.95 per Mcf in the first nine months of 2014 to $5.07 per Mcf in the first nine months of 2015.     

Natural gas production for the first nine months of 2015 decreased 2.3 Bcf, or 20%, resulting in a decrease in natural gas revenue of approximately $10.8 million.  This decline is primarily due to an emphasis on liquids-rich assets in our portfolio of assets.  Additionally, we sold the remaining interests in our largest natural gas field, Hilltop, at the end of the third quarter of 2014.    

Natural gas liquids revenues decreased $6.3 million, or 43%, during the first nine months of 2015 to $8.4 million from $14.7 million in the same period in 2014. The decrease in natural gas liquids revenue was attributable to a decrease in price during the first nine months of 2015 partially offset by an increase in production volumes.  A 57% decrease in our average price from $36.67 per Bbl in the first nine months  of 2014 to $15.81 per Bbl in the first nine month of 2015 was partially offset by a 32% increase in volumes from 400 MBbls to 527 MBbls.  The increase in volume is primarily due to increased production in our Sooner Trend field in Oklahoma from 233 Bbls to 376 Bbls in the first nine months of 2014 and 2015, respectively.

Other revenues decreased $0.1 million during the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014. The revenue is related to pipeline and processing fees from our East Texas properties.

Gain on sale of assets was $66.5 million in the first nine months of 2015, as compared to $87.1 million in the first nine months of 2014.  The 2014 gain was primarily due to the sale of a portion of our interests in our Eagleville field in the first quarter of 2014 and the sale of our Hilltop field in the third quarter of 2014.  The 2015 gain was primarily due to the sale of our remaining interests in the Eagleville field in the third quarter of 2015.

Gain — oil and natural gas derivative contracts was $83.6 million during the nine months ended September 30, 2015 as compared to a gain of $4.5 million during the same period in 2014. The fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods. The $83.6 million gain in the first nine months of 2015 is inclusive of $77.6 million in settlements received on oil and natural gas derivative contracts of which $32.9 million were related to unwinds of several oil and natural gas derivative contracts.    

Expenses 

Lease and plant operating expense decreased $1.8 million, or 3% in the first nine months of 2015 as compared to the first nine months of 2014, from $55.0 million to $53.2 million, primarily due to a decrease in marketing and gathering and salt water disposal of $5.5 million, partially offset by an increase in field services and rental equipment of $4.0 million. On a per unit basis, lease and plant operating expenses were $10.12 per BOE and $10.84 per BOE for the first nine months of 2015 and 2014, respectively. 

Production and ad valorem taxes decreased $10.1 million, or 44%, to $12.9 million for the first nine months of 2015, as compared to $23.0 million for the first nine months of 2014.  Production taxes decreased $9.2 million for the first nine months of 2015 as compared to the corresponding period of 2014,  primarily due to the decline in oil and natural gas revenue.  Production taxes are impacted by our mix of sales between oil and natural gas, as well as by varying rates and exemption opportunities in different states.  Ad valorem taxes decreased $0.8 million primarily due to our declining net profit interest from 50% of our original working interest in

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the first nine months of 2014 declining to 30% in the first nine months of 2015 related to the partial sale of our Eagleville field in first quarter of 2014.

Workover expense decreased $3.1 million during the first nine months of 2015 as compared to the first nine months of 2014. This expense varies depending on activities in the field and is attributable to many different properties.

Exploration expense includes dry hole costs and the costs of our geology department, costs of geological and geophysical data, expired leases, plug and abandonment expenditures, and delay rentals. Exploration expense decreased $6.8 million, from $44.0 million for the first nine months of 2014 to $37.2 million for the first nine months of 2015, primarily due to a decrease in G&G seismic expenses, dry hole costs and plug and abandonment expenditures during the first nine months of 2015 compared to the first nine months of 2014.  The first nine months of 2015 includes G&G seismic expense of $10.0 million, dry hole expense of $22.6 million and lease expense and expired leases of $3.5 million.

Depreciation, depletion and amortization increased $9.6 million to $111.9 million for the first nine months of 2015 as compared to $102.3 million for the first nine months of 2014. On a per unit basis, this expense increased from $20.17 per BOE in the first nine months of 2014 to $21.27 per BOE in the first nine months of 2015.  Depreciation, depletion and amortization is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense increased from $27.9 million in the first nine months of 2014 to $86.3 million in the first nine months of 2015. This expense varies with the results of drilling, as well as with price declines and other factors that may render some fields uneconomic, resulting in impairment.  Impairment expense in the first nine months of 2015 included a write-down of our Weeks Island Area and natural gas fields in South Texas, East Texas and South Louisiana.    The write-down in the first nine months of 2014 was related to several lower-margin fields in Texas and Louisiana.

Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $1.6 million for the first nine months of 2015 and $1.5 million for the corresponding period in 2014.

General and administrative expense decreased $10.4 million for the first nine months of 2015 to $45.5 million from $55.9 million for the first nine months of 2014. The decrease is principally due to the recapitalization expenditures of $13.9 million incurred in the first quarter of 2014, and a decrease in legal fees of $0.6 million, partially offset by an increase in litigation settlement expense of $2.7 million and Eagleville closing fees of $1.6 million.  On a per unit basis, general and administrative expenses were $8.64 per BOE and $11.01 per BOE for nine months ended September 30, 2015 and 2014, respectively.  

Interest expense, net increased $4.3 million for the first nine months of 2015 to $45.9 million from $41.6 million for the first nine months of 2014.  The increase is primarily due to interest incurred on the second lien senior secured term loan of $3.5 million that we entered into during the second quarter of 2015 and increased interest on our credit facility by $1.0 million due to a higher average outstanding balance.  The increase in interest expense during the nine months of 2015 was partially offset by interest income of $0.5 million.

Liquidity and Capital Resources 

Our principal requirements for capital are to fund our day-to-day operations, exploration and development activities, and to satisfy our contractual obligations, primarily for the repayment of debt and any amounts owed during the period related to our hedging positions.

Our 2015 capital budget is primarily focused on the development of existing core areas through exploitation and development. Currently, we plan to spend approximately $175 million in 2015 for exploration and development, of which 49% is allocated to our Sooner Trend properties and 27% allocated to Weeks Island area.  We have expended or accrued approximately $195 million through September 30, 2015, of which $46.2 million was utilized for the acquisition of undeveloped leasehold interest in Oklahoma.  We reduced our anticipated capital expenditures for 2015 from 2014 levels in response to the significant decline in oil prices in 2014 in order to preserve liquidity.  Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. Because a large percentage of our acreage is held by production, we have the ability to materially decrease our drilling and recompletion budget in response to market conditions with decreased risk of losing significant acreage.

We expect to fund the remainder of our 2015 capital expenditures for exploration, development, and acquisition of producing properties predominantly with cash flows from operations, supplemented by borrowings under our credit facility.  If necessary, we may also access capital through proceeds from potential non-core asset dispositions and the future issuances of debt and/or equity

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securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our senior secured revolving credit facility, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

In light of current market conditions, we and our affiliates continue to evaluate opportunities to retire or purchase our outstanding debt securities. We may use open market purchases, privately negotiated transactions, purchases under Rule 10b5-1 purchase plans or otherwise to accomplish the retirement or purchase of our debt. Whether we or our affiliates pursue or complete any such transactions will depend on prevailing market conditions, our liquidity requirements and funding availability, contractual restrictions and other factors, and there can be no assurance that any of these actions will be taken.

Senior Notes

We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective interest rate of 9.7825%. Interest is payable semi-annually each April 15th and October 15th. The senior notes are unsecured and are our general obligations, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility and senior secured term loan. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries.

The senior notes contain an optional redemption provision beginning October 15, 2014 allowing us to retire the principal outstanding, in whole or in part, at 104.813%. Additional optional redemption provisions allow for retirement at 102.406% and 100.0% beginning on each of October 15, 2015 and 2016, respectively.

Credit Facility

We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent, which matures October 13, 2017.  Our restricted subsidiaries are guarantors of the credit facility. 

The borrowing base is redetermined each May and November.  On September 30, 2015, as a result of our Eagle  Ford divestiture, our borrowing base was reduced from $300 million to $255 million.  On November 12, 2015, our borrowing base was redetermined and was increased to $300 million.  On November 12, 2015, outstanding borrowing under the credit facility was $148 million, letters of credit totaling $65,000 were outstanding, and the available unused portion of the borrowing base was $152 million.    If oil and natural gas prices continue to decline, the borrowing base under our credit facility may be reduced.

Our credit facility provides for two alternative interest rate bases and margins. Eurodollar loans accrue interest generally at the one-month London Interbank Offered Rate plus a margin ranging from 2.00% to 2.75%, depending on the utilization of our borrowing base. “Reference rate” loans accrue interest at the prime rate of Wells Fargo Bank, N.A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The weighted average rate on all outstanding borrowings as of September 30, 2015 under the credit facility was 2.85%, which was based on the Eurodollar option.

 

The credit facility contains customary covenants requiring us to maintain certain financial covenants including, among others, a current ratio, leverage ratio, and interest coverage ratio which are calculated quarterly.  At September 30, 2015, we were in compliance with the covenants of the credit facility.  The terms of the credit facility also restrict our ability to make distributions and investments. 

 

Senior Secured Term Loan

 

 On June 2, 2015, we entered into a second lien Senior Secured Term Loan Agreement (the “Term Loan Facility”) with Morgan Stanley Energy Capital Inc.  as administrative agent, and the lenders party thereto, pursuant to which we borrowed $125 million.  The Term Loan Facility includes an accordion feature which allows us to borrow up to an additional $50 million of term loans under the Term Loan Facility within one year following the closing, subject to certain conditions.  The Term Loan Facility matures on April 15, 2018. 

 

Borrowings under the Term Loan Facility bear interest at adjusted LIBOR plus 8%. The covenants in the Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) current assets to current liabilities of at least 1.0 to 1.0, (ii) debt to EBITDAX of no more than 4.5 to 1.0, (iii) PV-9 of total proved reserves to total secured debt of at least 1.5 to 1.0, and (iv) EBITDAX to interest expense of at least 2.5 to 1.0.  Obligations under the Term Loan Facility are guaranteed by certain of our subsidiaries and affiliates and are secured by second priority liens on substantially all of our and our subsidiaries assets that serve as collateral under the credit facility.  At September 30, 2015, we were in compliance with the covenants of the Term Loan Facility.

 

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We have the option to prepay all or a portion of the Term Loan Facility at any time, and we are subject to certain mandatory prepayments of proceeds from asset sales or an initial public offering, which are subject to certain prepayment premiums.  The net proceeds of $121 million from the Term Loan Facility were used to pay down outstanding amounts under our credit facility.

 

As of September 30, 2015, future maturities of our long-term debt, including notes payable to our founder, for the twelve months ending December 31, 2016 are as follows:

 

Cash flow provided by operating activities 

Operating activities provided cash of $155.2 million during the nine months ended September 30, 2015 as compared to $157.1 million during the comparable period in 2014, a decrease of $1.9 million.  The decrease in operating cash flows was attributable to various factors.  Cash-based items of net income, including revenues (exclusive of  unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net decrease of approximately $43.8 million.    Changes in working capital and other assets and liabilities resulted in an increase of $41.8 million in the first nine months of 2015 as compared to the corresponding period in 2014.

Cash flow used in investing activities 

Investing activities used cash of $208.2 million during the nine months ended September 30, 2015 as compared to $86.1 million during the comparable period of 2014.  Capital expenditures for property and equipment used cash of $184.5 million and $269.8 million in the first nine months of 2015 and 2014, respectively. Sales of properties provided proceeds of $0.3 million in the first nine months of 2015 and $218.5 million during the comparable period of 2014.  Acquisitions used cash of $48.6 million during the first nine months of 2015.  During the fourth quarter 2014, we sold our remaining interests in the Hilltop field and placed the net proceeds into a restricted cash account with a qualified intermediary available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code.  During the first quarter 2015, net proceeds in the restricted account provided proceeds of $24.6 million.    

Cash flow provided by (used in) financing activities 

Financing activities provided cash of $58.4 million during the nine months ended September 30, 2015 as compared to cash used by financing of $71.8 million during the comparable period in 2014.  In the first nine months of 2015, we received gross proceeds from the senior secured term loan of $125.0 million and drew down $102.5 million under the credit facility.  In addition, we made payments of $180.9 million to reduce the balance under our credit facility, including $120.9 million in net proceeds from the senior secured term loan.  Furthermore, we made distributions of $3.8 million and added $4.3 million of deferred financing costs related to the senior secured term loan during the nine months ended September 30, 2015.  We received $20.0 million of contributions from our Class B partners in the third quarter of 2015.

Cautionary Statement Regarding Forward-Looking Statements

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our 2014 Form 10-K and Part II, Item 1A of this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

 

Forward-looking statements may include statements about our:

 

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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 and production of oil and natural gas. These risks include, but are not limited to, commodity price volatility, low prices for oil and/or natural gas, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment and services, environmental risks, weather risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, access to capital, and the other risks described under “Item 1A. Risk Factors” in our 2014 Form 10-K.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers.  Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Prices for oil or natural gas remain depressed in the third quarter of 2015, and sustained lower prices will cause the twelve month weighted average price to decrease over time as the lower prices are reflected in the average price, which may reduce the estimated quantities and present values of our reserves.  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 oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in the 2014 Form 10-K or this report 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 report 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 Quarterly Report on Form 10-Q.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

For information regarding our exposure to certain market risks, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities—Commodity Derivative Instruments” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2014 Form 10-K. There have been no material changes to the disclosure regarding market risks other than as noted below. See Part I, Item 1, Note 6 to our consolidated financial statements for a description of our outstanding derivative contracts at the most recent reporting date.

The fair value of our oil and natural gas derivative contracts at September 30, 2015 was a net asset of $93.1 million. A 10% increase or decrease in oil and natural gas prices with all other factors held constant would result in a decrease or increase, respectively, in the estimated fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil

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and natural gas commodity contracts of approximately $25.7 million (decrease in value) or $23.8 million (increase in value), respectively, as of September 30, 2015.  

We are subject to interest rate risk on our variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivative contracts.  A 1% increase in interest rates would increase annual interest expense on our variable rate debt by approximately $2.4 million, based on the balance outstanding as of September 30, 2015.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2015 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

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

ITEM  1A. Risk Factors 

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in the 2014 Form 10-K. There have been no material changes with respect to the risk factors disclosed in the 2014 Form 10-K during the quarter ended September 30, 2015.  

ITEM  5. Other Information

On August 13, 2015, High Mesa contributed $20 million to us in connection with the issuance of Series C PIK convertible preferred stock of High Mesa (“Series C Issuance”) to Highbridge for gross proceeds of $25 million.  In connection with the Series C Issuance, Alta Mesa Holdings GP, LLC, High Mesa, as holder of 100% of our Class B Units, and all of our Class A Limited Partners entered into a Third Amended and Restated Limited Partnership Agreement to provide for the Series C Issuance in the distribution formula and certain other provisions of the amended partnership agreement.  We will use the capital to pay down amounts owed under the credit facility and for other general corporate purposes.

On August 13, 2015, Gene Cole was appointed to the board of directors of Alta Mesa Holdings GP, LLC.

Gene Cole joined us in 2007 and currently serves in the position of Vice President and Chief Technical Officer. Mr. Cole has over 25 years of extensive domestic and international oilfield experience in management, well completions, well stimulation design and execution. He started his career with Schlumberger Dowell as a Field Engineer and served in numerous increasingly responsible positions with Schlumberger in the areas of field operations, engineering and management. He has a Bachelor of Science in Petroleum Engineering from Marietta College.

ITEM  6. Exhibits

 

 

 

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SIGNATURES

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

 

 

 

 

 

 

 

 

 

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