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, 2016

FOR

☐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

(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 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 primarily engaged in the acquisition, exploration, development, and production of onshore oil and natural gas properties located primarily in Oklahoma and Louisiana. 



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, 2015 (the “2015 Annual Report”).  As of September 30, 2016, the Company’s significant accounting policies are consistent with those discussed in Note 2 in the 2015 Annual Report.

Principles of Consolidation and Reporting

The consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. The consolidated 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, 2015, which were filed with the Securities and Exchange Commission in our 2015 Annual Report.

The consolidated financial statements included herein as of September 30, 2016, and for the three and nine months ended September 30, 2016 and 2015, 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 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, state taxes, 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 Financial Accounting Standards Board (“FASB”) issued ASU No. 2014-09, Revenue from Contracts with Customers. The update provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU No. 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 August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date. ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.    

Additionally, in March 2016, the FASB issued ASU No. 2016-08, Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which clarifies the implementation guidance on principal versus agent considerations on such matters. In April 2016, the FASB issued ASU No. 2016-10, Identifying Performance Obligations and Licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the

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FASB issued ASU No. 2016-12, Narrow-Scope Improvements and Practical Expedients, which amends certain issues in ASU 2014-09 on transition, collectability, non-cash consideration, and the presentation of sales taxes and other similar taxes collected from customers. We are currently evaluating the impact of adopting this standard on our consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach.

In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU No. 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU No. 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU No. 2016-01 is effective for fiscal years beginning after December 15, 2017, 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.

 

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases.



In August 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments,  which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The guidance is effective for annual periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted, provided that all of the amendments are adopted in the same period.  This guidance must be adopted using a retrospective transition method. The Company is currently evaluating the effect that adopting this guidance will have on its consolidated statement of cash flows.





3.  ACQUISITION AND DIVESTITURE

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 senior secured revolving credit facility.

Divestiture

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”) was July 1, 2015.  



The aggregate cash purchase price for the Membership Interests was $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.



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

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approximately $1.4 million in pre-tax loss for the three months ended September 30, 2015 and approximately $0.4 million in pre-tax loss for the nine months ended September 30, 2015.  Subsequent to the Eagle Ford divestiture, we no longer own any assets in the Eagle Ford.





4.  PROPERTY AND EQUIPMENT



Property and equipment consists of the following (unaudited):  



Suspended exploratory well costs



Our net changes in deferred exploratory well costs for the nine months ended September 30, 2016, are presented below (unaudited):







The ending balance in deferred capitalized exploratory well costs includes the costs of five wells in two prospects.  At September 30, 2016, approximately $0.7 million of capitalized exploratory well costs had been capitalized for periods greater than one year.





















5. FAIR VALUE DISCLOSURES

The Company follows ASC 820, “Fair Value Measurements and Disclosures.” 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 estimate of our senior secured term loan is not considered to be materially different from carrying value as there were no significant changes in our credit risk.  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

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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 $422.5 million at September 30, 2016.  This estimation is based on the most recent trading values of the senior 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 $28.7 million were written down to their fair value of $14.5 million, resulting in an impairment charge of $14.2 million for the nine months ended September 30, 2016.  For the nine months ended September 30, 2015, 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. Oil and natural gas properties with a carrying amount of $1.2 million were written down to their fair value of $0.3 million, resulting in an impairment charge of $0.9 million for the three months ended September 30, 2016.  For the three months ended September 30, 2015, 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.    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 $1.0 million and $1.7 million in additions to asset retirement obligations measured at fair value during the nine months ended September 30, 2016 and 2015, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2016 and December 31, 2015, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value (unaudited):  

 

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, natural gas and natural gas liquids. From time to time, we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our oil, natural gas and natural gas liquids 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 oil production equivalent to barrels (Bbl) per month, gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month.  

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The contracts represent agreements between us and the counterparties 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. 

From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates. 

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 statements 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 and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:



Fair Values of Derivative Contracts (unaudited):

















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







 

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, 2016 (unaudited):  



OIL DERIVATIVE CONTRACTS













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We had the following open derivative contracts for natural gas at September 30, 2016 (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 various of these benchmarks.

We had the following open derivative contracts for natural gas liquids at September 30, 2016 (unaudited):



NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS





We had the following open financial basis swaps for natural gas at September 30, 2016 (unaudited):



BASIS SWAP DERIVATIVE CONTRACTS











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7. ASSET RETIREMENT OBLIGATIONS

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

 





8. LONG-TERM DEBT, NET AND NOTES PAYABLE TO FOUNDER

Long-term debt, net and notes payable to founder consists of the following (unaudited):  

 





Credit Facility.    On February 3, 2016, we entered into an Agreement and Amendment No. 13 (the “Thirteenth Amendment”) to the senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto. The Thirteenth Amendment, among other things: (a) permits us to enter into exchanges of outstanding senior notes for a third lien term loan, (b) permits us to draw the remaining borrowing base availability under the credit facility into a controlled account with such funds not being treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account, (c) permits us to dispose of oil and natural gas properties pursuant to the joint development agreement with BCE-STACK Development LLC (“BCE-STACK”), (d) requires that twice a month we transfer available cash in excess of $25 million to the controlled account, and (e) increases the maximum leverage ratio for the fiscal quarters ending June 30, 2016 and September 30, 2016 from 4.00 to 1.00 to 4.50 to 1.00.    On June 16, 2016, we entered into an Agreement and Amendment No. 14 (the “Fourteenth Amendment”) to the credit facility which, among other things: (a) reaffirmed our borrowing base at $300 million until the next scheduled redetermination,  and (b) increased the applicable margins to be applied based on the utilization of the borrowing base.  On March 16, 2016, we borrowed $141.9 million under the credit facility, which represented the remaining undrawn amount that was available under the credit facility.  As required by the terms of the credit facility, the borrowings were deposited into an account controlled by the administrative agent and are recorded on our consolidated balance sheet under “Short-term restricted cash.”  As of September 30, 2016, we have approximately $91.9 million remaining in the controlled account.  Such funds will not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account. These funds are available to be used for general corporate purposes.



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 borrowing base is currently $300 million and the principal amount is payable on the maturity date of October 13, 2017.  The credit facility borrowing base is redetermined semi-annually in May and November.    The credit facility bears interest at LIBOR plus applicable margins between 2.50% and 3.50% or a “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.50% to 2.50%, depending on the utilization of our borrowing base. The weighted average rate on outstanding borrowings was 4.13% as of September 30, 2016 and 2.87% as of December 31, 2015.  The letters of credit outstanding as of September 30, 2016 were approximately $7.6 million.



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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 4.5 to 1.0, which will decrease to 4.0 to 1.0 for the quarter ended December 31, 2016.  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, 2016, we were in compliance with all financial covenants of the credit facility. The borrowing base is subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined by the lenders under our credit facility, and other factors deemed relevant by our lenders. Recent declines in prices for oil and natural gas may cause our banks to reduce the borrowing base under our credit facility when it is next redetermined.



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 net proceeds of approximately $121 million from the Term Loan Facility, after payment of transaction-related fees and expenses, were used to pay down outstanding amounts under our existing credit facility.  The Term Loan Facility matures on April 15, 2018. The principal amount is payable at maturity. On February 3, 2016, we entered into the first amendment to the Term Loan Facility (the “First Amendment”). The First Amendment: (a) permits us to enter into exchanges of outstanding senior notes for  a third lien term loan, (b) allows us to dispose of oil and natural gas properties pursuant to the joint development agreement with BCE-STACK, (c) requires that twice a month we transfer available cash in excess of $25 million to a controlled account, with such funds in the controlled account to not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account, and (d) increases the maximum leverage ratio for the fiscal quarters ending June 30, 2016 and September 30, 2016 from 4.5 to 1.0 to 5.0 to 1.0.    



Borrowings under the Term Loan Facility bear interest at adjusted LIBOR plus 8.00%. 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 5.0 to 1.0 (decreasing to 4.5 to 1.0 for the quarter ended December 31, 2016), (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 subsidiaries assets that serve as collateral under the credit facility.    As of September 30, 2016, we were in compliance with all financial 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.    No such prepayment has occurred as of September 30, 2016.

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% at September 30, 2016.    Interest is payable semi-annually each April 15th and October 15th.  The senior notes are unsecured and are general obligations, and effectively rank junior to any of our existing or future secured indebtedness, which 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 $1.0 million and $1.4 million at September 30, 2016 and December 31, 2015, 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. 

Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless we have previously or concurrently exercised our right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase.

Notes Payable to Founder. We have notes payable to our founder (“Founder Notes”) that bear simple interest at 10% with a balance of $26.7 million and $25.7 million at September 30, 2016 and December 31, 2015, respectively.  The maturity date was extended on March 25, 2014 from December 31, 2018 to December 31, 2021.  Interest and principal are payable at maturity. Our founder shall convert the notes 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. 

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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 Founder Notes amounted to $0.9 million for each of the nine months ended September 30, 2016 and 2015 and $0.3 million for each of the three months ended September 30, 2016 and 2015. Such amounts have been added to the balance of the Founder Notes.

Deferred financing costs. As of September 30, 2016, the Company had $6.8 million of deferred financing costs related to the credit facility, Term Loan Facility and senior notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $5.5 million related to the Term Loan Facility and senior notes are netted with long-term debt on the consolidated balance sheet as of September 30, 2016 in accordance with ASU No. 2015-03, which we adopted in the fourth quarter of 2015.  Deferred financing costs of $1.3 million and $1.2 million related to the credit facility are included in deferred financing costs, net on the consolidated balance sheets at September 30, 2016 and December 31, 2015, respectively. Amortization of deferred financing costs recorded for the nine months ended September 30, 2016 and 2015 was $3.0 million and $2.5 million, respectively. Amortization of deferred financing costs recorded for the three months ended September 30, 2016 and 2015 was $1.0 million and $0.9 million, respectively.  These costs are included in interest expense on the consolidated statements of operations.

9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The following provides the details of accounts payable and accrued liabilities (unaudited):  











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.  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, 2016.

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 $1.3 million at September 30, 2016 and December 31, 2015, respectively, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.  

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 (collectively, “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.  Plaintiffs claim they are owners of land upon which oil

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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, 2016, we have accrued approximately $4.0 million ($0.8 million in current liabilities and $3.2 million in other long-term liabilities) as the outcome of the litigation was deemed probable and estimable.    The settlement requires payment over the term of six years.      

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 designated value (“SIDV”).  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 SIDV 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 2016,  we granted 360,000 new PARs with a SIDV of $40 and terminated 24,500 PARs with a SIDV of $40, resulting in 577,000 PARs issued at a weighted average of $36.79 as of September 30, 2016. 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, 2016 or December 31, 2015.

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 have been highly volatile and declined dramatically since the second half of 2014 and remain depressed as of September 30, 2016.  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 oil and natural gas 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 2016 from 2015 levels.   This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce.  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, natural gas and natural gas liquids 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.  The Class B partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture. 

On August 31, 2016, our Class B partner completed the sale of preferred stock to BCE-MESA Holdings LLC (“Bayou City”).  In connection with the sale of preferred stock, our General Partner, Class B partner, and all of our Class A partners entered into a Fourth Amended and Restated Limited Partnership Agreement (the “Amended Partnership Agreement”).  The Amended Partnership Agreement provides, among other things, for certain drag-along rights, including the mandatory contribution to the Class B partner by the Class A partners of their remaining Class A units upon an initial public offering. 

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In addition, on August 31, 2016, the owners of our General Partner entered into a Third Amended and Restated Limited Liability Company Agreement, which was amended to provide that the number of members of the board of managers of our General Partner be (the “Board”) increased to match the number of members of the board of directors of our Class B partner. William W. McMullen was appointed to the board of managers of our General Partner.  Mr. McMullen is the founder and managing partner of Bayou City Energy Management, LLC (“BCE Management”).

On September 30, 2016, our Class B partner completed an additional sale of preferred stock to Bayou City.  In connection with this investment, Mark Stoner, as a nominee of Bayou City, was appointed to the board of managers of our General Partner.

Distribution and Income Allocation:  All distributions under the Amended Partnership Agreement shall first be made to 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 (as defined below) is distributed to the Class A and Class B partners according to a variable formula as defined in the Amended 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 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.  We made no distributions for the nine months ended September 30, 2016.



13.  RELATED PARTY TRANSACTIONS

Our wholly-owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “Joint Development Agreement”), dated January 13, 2016, with BCE-STACK, a fund advised by BCE Management, to fund drilling operations in Kingfisher County, Oklahoma. As described in Note 12, Mark Stoner and William W. McMullen, partners at BCE Management, were appointed to the board of managers of our General Partners during the third quarter 2016.  The drilling program provides for the development of sixty identified well locations.  BCE-STACK has committed to fund 100% of Oklahoma Energy’s working interest share of drilling and development costs for each well in which BCE-STACK elects to participate (each, a “Joint Well”), provided that to the extent that the total cost of drilling the wells in any tranche exceeds $64 million, Oklahoma Energy will be responsible for its and BCE-STACK’s working interest share of the drilling costs in such tranche exceeding such limit.

In exchange for the payment of drilling and completion costs, BCE-STACK will receive 80% of Oklahoma Energy’s working interest in each Joint Well, which interest will be reduced to 20% of Oklahoma Energy’s initial working interest upon BCE-STACK achieving a 15% internal rate of return in a tranche, and further reduced to 7.5% of Oklahoma Energy’s initial interest upon BCE achieving a 25% internal rate of return. Upon the achievement of these return thresholds, the interest BCE-STACK relinquishes will be automatically assigned back to Oklahoma Energy. Following the completion of each Joint Well, BCE-STACK and Oklahoma Energy will bear their proportionate working interest share of all subsequent costs and expenses related to such Joint Well.  The approximate dollar value of the amount involved in this transaction or Mark Stoner and William W. McMullen’s (“Directors”) interests in the transaction depends on a number of factors outside our Directors control and is not known at this time.

As of September 30, 2016, we recorded $13.4 million in payables due to affiliates on our consolidated balance sheet, which represents net advances from BCE-STACK for their working interest share of the drilling and development cost as part of our Joint Development Agreement.

14. 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 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.

15.  SUBSEQUENT EVENTS

Class B Partner Contribution.    In October 2016, our Class B partner, completed the final stage of the sale of preferred stock to Bayou City as described in Note 12. In connection with the final sale of preferred stock to Bayou City, our Class B partner contributed $300 million from the Bayou City investment to us.  We used a portion of the contribution to repay all amounts outstanding under the Term

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Loan Facility of $127.5 million, which includes a $2.5 million prepayment premium for repaying all amounts owed under the Term Loan Facility prior to maturity date.  The remaining funds are available to be used for general corporate purposes.

Amended and Restated Credit Facility.  On November 10, 2016, we amended and restated the credit facility.  The amended and restated credit facility, among other things, extends the maturity of the credit facility to April 14, 2018 effective immediately, and ultimately to November 10, 2020 subject to the completion of a refinancing or an extension of the maturity date of the senior notes. The amended and restated credit facility also reaffirms the existing borrowing base amount of $300.0 million through the new redetermination of the borrowing base.  Additionally, the amended and restated credit facility increases our pricing grid by 25 to 50 basis points (depending on our leverage ratio) and increases our mortgage requirement from 85% of the value of our proven reserves to 90%.





 



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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 consolidated financial statements and related notes included elsewhere in this report. In addition, such analysis should be read in conjunction with the consolidated financial statements and the related notes included in our Annual Report on Form 10-K for the year ended December 31, 2015 (“2015 Annual Report”).  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 2015 Annual Report, 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 the onshore oil and natural gas acquisition, exploitation, exploration and production in the United States since 1987.  Currently, we are focusing on the development and acquisition of unconventional oil and natural gas reserves in the Sooner Trend area of the Anadarko Basin in Oklahoma.  We also operate, develop, and explore for conventional oil and natural gas reserves, with our most significant conventional asset being the Weeks Island oil field in Iberia Parish, Louisiana.  We maintain operational control of the majority of our properties, either through directly operating them, or through operating arrangements with minority interest holders.  Our operations also include other oil and natural gas interests in Texas and Louisiana.

The amount of income 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, natural gas and natural gas liquids 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, natural gas and natural gas liquids prices on our cash flows.

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

Recent Developments

Class B Partner Investment and Contribution.    On August 31, 2016, our Class B partner,  High Mesa completed the sale of preferred stock to Bayou City, a fund advised by BCE Management.  In connection with the sale of preferred stock, our General Partner, Class B partner, and all of our Class A partners entered into the Amended Partnership Agreement.  In addition, the owners of our General Partner entered into a Third Amended and Restated Limited Liability Company Agreement, which was amended to provide that the number of members of the board of managers of our General Partner be increased to match the number of members of the board of directors of our Class B partner. William W. McMullen was appointed to the board of managers of our General Partner.  Mr. McMullen is the founder and managing partner of BCE Management. On September 30, 2016, our Class B partner completed an additional sale of preferred stock to Bayou City.  In connection with this investment, Mark Stoner, as a nominee of Bayou City, was appointed to the board of managers of our General Partner.

In October 2016, our Class B partner, completed the final stage of the sale of preferred stock to Bayou City. In connection with the final sale of preferred stock to Bayou City, our Class B partner invested $300 million from the Bayou City investment in us in November 2016.  We used a portion of the contribution to repay all amounts outstanding under the Term Loan Facility of $127.5 million, which includes a $2.5 million prepayment premium for repaying all amounts owed under the Term Loan Facility prior to maturity date.  The remaining funds are available to be used for general corporate purposes.



Amended and Restated Credit Facility.  On November 10, 2016, we amended and restated the credit facility.  The amended and restated credit facility, among other things, extends the maturity of the credit facility to April 14, 2018 effective immediately, and ultimately to November 10, 2020 subject to the completion of a refinancing or an extension of the maturity date of the senior notes. The amended and restated credit facility also reaffirms the existing borrowing base amount of $300.0 million through the new redetermination of the borrowing base.  Additionally, the amended and restated credit facility increases our pricing grid by 25 to 50 basis points (depending on our leverage ratio) and increases our mortgage requirement from 85% of the value of our proven reserves to 90%.

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Outlook, Market Conditions and Commodity Prices 

Our revenue, profitability and future growth depend on many factors, particularly the prices of oil, natural gas and natural gas liquids, which are beyond our control.  The relatively low level of natural gas prices prompted our shift in emphasis to oil and natural gas liquids over the past several years.  Accordingly, the success of our business is significantly affected by the price of oil due to our current focus on development of oil reserves and exploration for oil.  Oil prices are subject to significant changes.  Beginning in the third quarter of 2014, the price for oil began a dramatic decline, and current prices for oil are significantly less than they have been over the last several years.  Factors affecting the oil prices include worldwide economic conditions, including the European credit markets; geopolitical activities, including developments in the Middle East, South America, and elsewhere; worldwide supply conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets.  Sustained low prices for oil, natural gas and natural gas liquids could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves, and our ability to finance operations, including the amount of our borrowing base under our credit facility.

During the last twelve month period ended September 30, 2016, NYMEX West Texas Intermediate (“NYMEX WTI”) oil prices ranged from a high of $48.85 per Bbl in June 2016 to a low of $30.62 per Bbl in February 2016.  During the third quarter of 2016, NYMEX WTI prices averaged approximately $44.94 per Bbl compared to $46.43 per Bbl for the same period of 2015.  We received an average price of $43.08 per Bbl for the third quarter of 2016 before the effects of hedging.  NYMEX Henry Hub natural gas prices (“NYMEX HH”) have also been volatile and ranged from a high of $2.92 per MMBtu in July 2016 to a low of $1.71 in March 2016. We received an average price of $2.53 per Mcf for natural gas in the third quarter of 2016 before the effects of hedging. Although oil and natural gas prices have recently begun to recover from the lows experienced during the first quarter of 2016, forecasted prices for both oil and natural gas remain depressed.  The duration and magnitude of changes in oil and natural gas prices cannot be predicted.

Depressed oil, natural gas and natural gas liquids prices have impacted our earnings by necessitating impairment write-downs in 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 $14.2 million and $86.3 million for the nine months ended September 30, 2016 and 2015, respectively.  In  the first nine months of 2016 and 2015, write-downs were primarily due to downward revisions in proved reserves in some fields and the effects of decreased prices for oil, natural gas and natural gas liquids.  In the first nine months of 2016, our impairments were primarily related to a  frontier exploration area.  In the first nine months of 2015, our impairments were primarily related to the Weeks Island Area and non-core natural gas fields.  Further declines in oil and/or natural gas prices may result in additional impairment expenses.

Sustained low prices for oil, natural gas or natural gas liquids 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. It is also reasonably possible that prolonged low or further declines in commodity prices, further changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in additional impairments.  As a result of depressed prices and in order to preserve our liquidity, we reduced our budgeted capital expenditures for 2016 from 2015 levels.  Low prices may also reduce our cash available for distribution, acquisitions 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, natural gas and natural gas liquids.  Changes in these derivative assets and liabilities are reported in our consolidated statements  of operations as gain / loss on derivative contracts, which include both the non-cash increase and 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 2016, we recognized a net loss on our derivative contracts of $24.0 million, which includes $83.8 million in cash settlements received on derivative contracts. The $83.8 million in cash settlements received during the first nine months of 2016 includes approximately $58.4 million from settlement of several of our oil and natural gas derivative contracts prior to contract expiry.  The objective of our hedging program is that, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil, natural gas and natural gas liquids 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  these gains and losses will continue to reflect changes in oil, natural gas and natural gas liquids prices.

As of September 30, 2016, we have hedged approximately 81% of our forecasted production of proved developed producing reserves through 2019 at weighted average annual floor prices ranging from $2.90 per MMBtu to $4.50 per MMBtu for natural gas and $48.81 per Bbl to $53.36 per Bbl for oil.  If oil, natural gas and natural gas liquids prices continue to decline for an extended period of time, we may be unable to replace expiring hedge contracts or enter new contracts for additional oil, natural gas and natural gas liquids production at favorable prices. 

The primary factors affecting our production levels are capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program, and our inventory of drilling prospects.  In addition, we face the challenge of natural production declines.  We attempt to overcome this natural decline primarily through development of our existing undeveloped reserves, enhanced completions,  well recompletions, and other enhanced recovery methods. Our future growth will depend on our

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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.

Operations Update

Sooner Trend STACK.    The Sooner Trend is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal and vertical target horizons, extensive production histories, long-lived reserves and historically-high drilling success rates.  Our Sooner Trend properties consist largely of contiguous leased acreage primarily in Kingfisher County, Oklahoma, which is the eastern portion of the Anadarko Basin referred to as the STACK, an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked pay zones present in the area.  This continuously growing position is characterized by multiple productive zones at depths between 4,000 feet and 8,000 feet.  The legacy operations within our acreage are primarily shallow-decline, long-lived oil fields developed on 80-acre vertical well spacing associated with waterfloods in the Oswego, Big Lime and Manning Limestones.  We continue to maintain production in these historical field pay zones.  More recently, our focus in the STACK has been to implement a multi-year, multi-rig program to develop the Mississippian-age Osage and Meramec formations underlying the waterflood zones, as well as the Pennsylvanian-age Oswego formation, using horizontal drilling and multi-stage hydraulic fracturing technology.  We intend to supplement this activity with horizontal wells targeting various stacked pay intervals in the Big Lime, Prue, Skinner, Red Fork, Cherokee Shale, Manning Lime, Woodford Shale, and Hunton Lime formations to the extent commodities prices and cost efficiencies would provide sufficient returns.  We have positioned ourselves for expanded horizontal development of stacked pays, both within and contiguous with our legacy position in the Sooner Trend. 

 In the third quarter of 2016, we completed twenty-two horizontal wells in the Osage formation in the Sooner Trend.  Ten of the completed wells for the third quarter of 2016 were funded through of our Joint Development Agreement with BCE-STACK.    We had twenty-three horizontal wells in progress as of the end of the third quarter of 2016,  nine of which were funded through our joint development agreement with BCE-STACK.  Seven of the twenty-three horizontal wells in progress as of September 30, 2016 were on production subsequent to quarter end. 

As of September 30, 2016, we had four drilling rigs operating in the Sooner Trend for horizontal development.  We plan to utilize up to five drilling rigs during the fourth quarter of 2016 targeting the Mississippian-age Osage, Meramec, Manning, and the Pennsylvanian age Oswego formations with horizontal drilling.  We will also participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Osage formations. 

Production from our Sooner Trend properties in the third quarter of 2016 was an average of approximately 13,600 BOE/day net to our interest, 67% oil and natural gas liquids, as compared to an average of approximately 9,500 BOE/day, 76% oil and natural gas liquids, in the third quarter of 2015.  Production from our Sooner Trend properties in the first nine months of 2016 was an average of approximately 12,300 BOE/day net to our interest, 72% oil and natural gas liquids, as compared to an average of approximately 8,600 BOE/day, 78% oil and natural gas liquids, in the first nine months of 2015.

Weeks Island Area.    We continue to operate and develop for conventional oil and natural gas reserves in the Weeks Island Area.  The Weeks Island Area consists of our Weeks Island field and Cote Blanche Island field, located in Iberia and St. Mary Parishes, Louisiana.    

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 Weeks Island field in St. Mary Parish. The field is a salt dome structure and production from the Miocene sands discovered in 1948 by Texaco, three years after the discovery at Weeks Island field. The geology is similar to Weeks Island and we plan on utilizing the same geologic interpretation methods and engineering development techniques at Cote Blanche that we use at Weeks Island to increase reserves and production.  We believe these fields offer significant future opportunities for added production and reserves with development drilling, including pay zones targeted through use of recently merged, re-processed and re-interpreted 3-D seismic data.

In response to declining commodity prices, we are focusing our efforts on maintaining production through more efficient lifting operations.  Production from the Weeks Island  Area in the third quarter of 2016 was approximately 3,100 BOE/day, net to our interest, 91% oil, as compared to 4,700 BOE/day, 86% oil, for the third quarter of 2015.  Production from the Weeks Island Area in the first nine months of 2016 was approximately 3,700 BOE/day, net to our interest, 91% oil, as compared to 4,700 BOE/day, 84% oil in the first nine months of 2015.



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Results of Operations: Three Months Ended September  30,  2016 v. Three Months Ended September  30, 2015





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Revenues

Oil revenues in the three months ended September 30, 2016 decreased $9.5 million, or 19%,  to $40.7 million from $50.2 million in the corresponding period in 2015. The decrease in revenue was primarily attributable to a decrease in average price as well as a decrease in production during the third quarter of 2016.   The average price of oil exclusive of derivative contract settlements decreased $2.75 per Bbl or 6% in the third quarter of 2016 compared to the third quarter of 2015, resulting in a decrease in oil revenues of approximately $2.6 million. When including the effects of derivative contract settlements, the overall price decreased 5% from $63.78 per Bbl in the third quarter of 2015 to $60.35 per Bbl in the third quarter of 2016.  The overall price in the third quarter 2016 included settlements of oil derivative contracts prior to contract expiry of approximately $18.2 million.  Production decreased 150 MBbls,  resulting in a decrease of $6.9 million in oil revenues.  The difference in production is primarily due to the sale of our Eagleville field in 2015 of 118 MBbls and natural decline in production in the Weeks Island Area of 109 MBbls, partially offset by an increase in production in the Sooner Trend Area of 90 MBbls.

Natural gas revenues in the three months ended September 30, 2016 increased $1.4 million, or 17%, to $9.8 million from $8.4 million in the same period of 2015. The increase in natural gas revenue was primarily attributable to an increase in production, partially offset by a slight decrease in average price exclusive of derivative contract settlements during the third quarter of 2016.  Production increased 0.6 Bcf resulting in an increase of $1.6 million in natural gas revenues. Although we continue to have an emphasis on liquids-rich assets in our portfolio, this increase is primarily due to natural gas produced in association with oil.  The average price of natural gas exclusive of derivative contract settlements decreased $0.04 per Mcf in the third quarter of 2016, resulting in a decrease in natural gas revenues of approximately $0.2 million.  When including the effects of derivative contract settlements, the overall price increased 21% from $2.41 per Mcf in the third quarter of 2015 to $2.92 per Mcf in the third quarter of 2016. 

Natural gas liquids revenues increased $1.5 million, or 59%, during the third quarter of 2016 to $4.0 million from $2.5 million in the same period in 2015. The increase in natural gas liquids revenue was attributable to increased production volumes during the third quarter of 2016, as well as a higher average price.    Production increased 66 MBbls  from 188 MBbls to 254 MBbls, resulting in an increase of $0.9 million in natural gas liquids revenues.  The increase in production is primarily due to an increase in production in our Sooner Trend Area of 75 MBbls partially offset by a decrease in production in non-core fields of 10 MBbls.    The average price of natural gas liquids exclusive of derivative contract settlements increased $2.33 per barrel or 17% in the third quarter of 2016 compared to the third quarter of 2015, resulting in an increase in natural gas liquids revenues of $0.6 million.  We entered into natural gas liquids derivative contracts during the fourth quarter of 2015 and the effective dates of those contracts were January 1, 2016.  The overall price including derivative contract settlements increased 18% from $13.42 per Bbl in the third quarter of 2015 to $15.85 per Bbl in the third quarter of 2016. 

Gain (Loss) on sale of assets was a loss of $8,000 in the third quarter of 2016 as compared to a gain of $66.4 million in the third quarter of 2015.    The gain recorded in the third quarter of 2015 is primarily related to the sale of all of the membership interests in Alta Mesa Eagle, LLC, which owned our remaining interests in the Eagleville field.



Gain on derivative contracts was a gain of $3.5 million in the third quarter of September 30, 2016 as compared to a gain of $72.0 million during the same period in 2015.  The fluctuation from period to period is due to the volatility of oil, and natural gas prices and changes in our outstanding hedge contracts during these periods.    The $3.5 million gain in the third quarter of 2016 is inclusive of $17.8 million from settlements received on our derivative contracts of which $18.2 million were from settlements of oil and natural gas derivative contracts prior to contract expiry.  The $72.0 million gain in the third quarter of 2015 is inclusive of $19.1 million in settlements received on oil and natural gas derivative contracts of which $0.3 million were  from settlements of natural gas derivative contracts prior to contract expiry. 

Expenses

Lease and plant operating expense increased $0.6 million or 3% in the third quarter of 2016 as compared to the third quarter of 2015, to $19.9 million from $19.3 million.  In general, there was an increase in marketing and gathering and compression expense of approximately $4.5 million partially offset by a decrease in field services, rental equipment, chemicals, and salt water disposal of $4.0 million.  On a per unit basis, lease and plant operating expense  was  $10.79 per BOE and $10.58 per BOE in the third quarter of 2016 and 2015, respectively.    

Production and ad valorem taxes decreased $1.5 million, or 34%, to $2.9 million in the third quarter of 2016, as compared to $4.4 million in the third quarter of 2015.  Production taxes decreased from $3.5 million in the third quarter of 2015 to $2.3 million in the third quarter of 2016,  primarily due to the decline in oil and natural gas revenues.  Ad valorem taxes decreased approximately $0.3 million in the third quarter of 2016 from the corresponding period of 2015 primarily due to the sale of our Eagleville field during the third quarter of 2015.

Workover expense decreased $0.2 million during the third quarter of 2016, as compared to the third quarter of 2015. This expense varies depending on activities in the field and is attributable to many different properties.

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Exploration expense includes dry hole costs, the costs of our geology department, costs of geological and geophysical data, expired leases, plug and abandonment expenditures, and delay rentals.  Exploration expense increased from $6.8 million in the third quarter of 2015 to $8.6 million in the third quarter of 2016, primarily due to an increase in geologic and geophysical (“G&G”)  seismic expense and expired leases of $5.5 million partially offset by a decrease in dry hole and plugging and abandonment costs of $3.8 million in the third quarter of 2016 as compared to the third quarter of 2015.

Depreciation, depletion and amortization expense decreased from $32.9 million in the third quarter of 2015 to $22.4 million in the third quarter of 2016. On a per unit basis, this expense decreased from $18.03 per BOE in the third quarter of 2015 to $12.17 per BOE in the third quarter of 2016.  The 2016 depletion rate per BOE was partially lower due to the impairment of proved properties in 2015 and the first half of 2016, which lowered the depletable base. Depreciation, depletion, and amortization is a function of capitalized costs of proved properties, proved reserves and production by field. 

Impairment expense decreased from $8.9 million in the third quarter of 2015 to $0.9 million in the third quarter of 2016. This expense varies with the results of exploratory and development drilling, as well as with well performance, commodity price declines and other factors that may render some fields uneconomic, resulting in impairment.  Impairment expense in the third quarter of 2016 included a write-down of $0.8 million in non-core areas.  Impairment expense in the third quarter of 2015 included a write-down of natural gas fields in South Louisiana and South Texas.

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 $0.5 million for the third quarter of 2016 and $0.6 million for the third quarter of 2015. 

General and administrative expense decreased $5.1 million in the third quarter of 2016 to $10.7 million from $15.8 million in the third quarter of 2015.  The decrease is primarily due to lower salaries and wages of $1.3 million, bonus accruals of $2.1 million, and consulting fees of $1.7 million.  On a per unit basis, general and administrative expenses were $5.78 per BOE and $8.64 per BOE in the third quarters of 2016 and 2015, respectively.

Interest expense, net increased from $16.7 million in the third  quarter of 2015 to $17.9 million in the  third quarter of 2016. Interest on our credit facility increased $1.2 million in the third quarter of 2016 as compared to the third quarter of 2015 as we drew down our remaining borrowing base capacity during the first quarter of 2016.































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     Results of Operations: Nine Months Ended September 30, 2016 v. Nine Months Ended September 30, 2015







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Revenues

Oil revenues in the nine months ended September 30, 2016 decreased $44.0 million, or 28%, to $115.8 million from $159.8 million for the corresponding period in 2015. The decrease in oil revenue was attributable to a lower average price as well as decreased production volumes. The average price of oil exclusive of derivative contract settlements decreased 22% in the first nine months of 2016, resulting in a decrease in oil revenues of approximately $32.6 million.  The overall price, including settlements of derivative contracts, decreased 4% from $67.20 per Bbl in the first nine months of 2015 to $64.60 per Bbl in the first nine months of 2016.   An approximate $11.4 million decrease in oil revenues in the first nine months of 2016 was due to a decrease in production of 231 MBbls, or 7%. This decrease is primarily due to the sale of our Eagleville field during the third quarter of 2015 and natural decline in production in our Weeks Island Area, partially offset by an increase in production from the Sooner Trend Area.  The sale of Eagleville and natural decline production of our Weeks Island Area decreased production by 589 MBbls.  The Sooner Trend Area increased production by 381 MBbls, from 1,458 MBbls in the first nine months of 2015 to 1,839 MBbls in the corresponding period of 2016.    

Natural gas revenues in the nine months ended September 30, 2016 decreased $4.5 million, or 18%, to $20.3 million from $24.8 million for the same period in 2015. The decrease in natural gas revenue was attributable to a decrease in price, partially offset by an increase in production during the first nine months of 2016.  The average price of natural gas exclusive of derivative contract settlements decreased 26% in the first nine months of 2016, resulting in a decrease in natural gas revenues of approximately $7.0 million.  The overall price, including derivative contract settlements, decreased 47% from $5.07 per Mcf in the first nine months of 2015 to $2.70 per Mcf in the first nine months of 2016.   The overall price in the first nine months of 2016 includes $2.4 million we received related to the settlement of several of our natural gas derivative contracts prior to contract expiry as compared to $14.7 million we received related to similar settlements of natural gas derivative contracts prior to expiry in the corresponding period in 2015.  An approximate $2.5 million increase in natural gas revenues was due to an increase in production of 0.9 Bcf, or 10%.    The increase is primarily due to an increase in production from the Sooner Trend Area of 2.6 Bcf partially offset by a decline in production in our Weeks Island Area of 0.7 Bcf and the sale of our Eagleville field during the third quarter of 2015 of 0.4 Bcf.

Natural gas liquids revenues increased $1.8 million, or 21%, in the first nine months of 2016 to $10.1 million from $8.3 million in the same period in 2015. The increase in natural gas liquids revenue was attributable to an increase in production volumes, partially offset by a decrease in price in the first nine months of 2016.  The increase in volume is primarily due to increased production in our Sooner Trend Area of 214 MBbls.  The increase in volume in the Sooner Trend Area was partially offset by the decrease in volume of 80 MBbls due to the sale of our Eagleville field, resulting in an increase in natural gas liquids revenues of approximately $2.6 million.  The average price of natural gas liquids exclusive of derivative contract settlements decreased $1.19 per Bbl or 8% in the first nine months of 2016 compared to the first nine months of 2015, resulting in a decrease in natural gas liquids revenues of $0.8 million.  We entered into natural gas liquids derivative contracts during the fourth quarter of 2015 and the effective dates of those contracts were January 1, 2016.  The overall price including derivative contract settlements decreased 7% from $15.81 per Bbl to $14.67 per Bbl for the first nine months of 2015 and 2016, respectively.     

Gain on sale of assets was $3.7 million in the first nine months of 2016, as compared to $66.5 million in the first nine months of 2015.  The $3.7 million gain in the first nine months of 2016 was due to the sale of certain non-core assets.    The 2015 gain was primarily due to the sale of all of the membership interests in Alta Mesa Eagle, LLC, which owned our remaining interests in the Eagleville field in the third quarter of 2015.

Gain (loss) on derivative contracts was a loss of $24.0 million during the nine months ended September 30, 2016 as compared to a gain of  $83.6 million during the same period in 2015. The fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedge contracts during these periods. The $24.0 million loss in the first nine months of 2016 is inclusive of $83.8 million in settlements received on derivative contracts of which $58.4 million were from settlements of oil and natural gas derivative contracts prior to expiry.  The $83.6 million gain in the first nine months of 2015 is inclusive of $77.6 million in settlements received on derivative contracts of which $32.9 million were from settlements of oil and natural gas derivative contracts prior to expiry.   

Expenses 

Lease and plant operating expense increased $0.1 million in the first nine months of 2016 as compared to the first nine months of 2015, from $53.2 million to $53.3 million, primarily due to an increase in marketing and gathering and rental equipment totaling $5.1 million, partially offset by a decrease in field services, transportation, repairs and maintenance,  salt water disposal, and chemicals of $5.0 million. On a per unit basis, lease and plant operating expenses were $9.98 per BOE and $10.12 per BOE for the first nine months of 2016 and 2015, respectively. 

Production and ad valorem taxes decreased $4.9 million, or 38%, to $8.0 million in the first nine months of 2016, as compared to $12.9 million in the first nine months of 2015.  Production taxes decreased $4.2 million in the first nine months of 2016 as compared to the corresponding period of 2015, as a result of the decline in oil and natural gas revenues.  Ad valorem taxes decreased $0.7 million, primarily due to the sale of our Eagleville field during the third quarter of 2015.

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Workover expense decreased from $4.1 million in the first nine months of 2015 to $3.2 million in the first nine months of 2016. 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 $21.9 million, from $37.2 million in  the first nine months of 2015 to $15.3 million in the nine months of 2016, primarily due to a decrease in dry hole expenses of $22.1 million, and a decrease in G&G expenses of $3.7 million. This decrease was partially offset by an increase in leasehold expense in the first nine months of 2016 of $4.0 million.

Depreciation, depletion and amortization expense decreased $45.0 million to $66.9 million in the first nine months of 2016 as compared to an expense of $111.9 million in the first nine months of 2015. On a per unit basis, this expense decreased from $21.27 per BOE in the first nine months of 2015 to $12.51 per BOE in the first nine months of 2016.   The 2016 depletion rate per BOE was lower due to the impairment of proved properties in 2015 and the first half of 2016, which partially lowered the depletable base.  The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense decreased $72.1 million from $86.3 million in the first nine months of 2015 to $14.2 million in the first nine months of 2016. 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.    Impairment expense in the first nine months of 2016 included a write-down of $10.3 million associated with the impact of low commodity prices on frontier exploration areas.

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 in each of the first nine months of 2016 and 2015.  

General and administrative expense decreased $12.5  million from $45.4  million in the first nine months of 2015 to $32.9 million in the first nine months of 2016.  The decrease is primarily due to lower salaries and wages of $1.1 million, bonus accruals of $6.2 million, accrued legal settlement expense in 2015 of $5.4 million and consulting fees of $1.7 million related to the sale of the Eagleville field in 2015, partially offset by exchange transaction fees and senior credit facility arrangement fees of $1.8 million recorded in the first nine months of 2016. 

Interest expense, net increased $5.7 million in the first nine months of 2016 to $51.6 million from $45.9 million in the first nine months of 2015.  We incurred additional interest of $4.7 million on the senior secured term loan that we entered into during the second quarter 2015. Interest on our credit facility increased $0.7 million in the first nine months of 2016 as compared to the same period in 2015 due to higher average outstanding balances.    

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 payment of debt interest and any amounts owed during the period related to our hedging positions.

Our 2016 capital budget is primarily focused on the development of existing core areas through exploitation and development. Currently, we plan to spend approximately $123 million in 2016 for exploration and development, of which over 90% is allocated to our Sooner Trend and  Weeks Island Areas.  The revised capital expenditure for 2016 reflects our plans to drill wells that are funded through the joint development agreement with BCE-STACK for the remainder of the year.  We have expended or accrued approximately $93 million of our capital budget through September 30, 2016.    We reduced our anticipated capital expenditures for 2016 from 2015 levels in response to the continued depressed oil prices and 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 increase or 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 2016 capital expenditures predominantly with cash flows from operations, drilling and completion capital funded through our joint development agreement with BCE-STACK, and capital contributions from our Class B partner, supplemented by borrowings under our credit facility.  If necessary, we may also access capital through proceeds from potential asset dispositions and the future issuances of debt and/or equity 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 facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our

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cash flows are materially less than anticipated and other sources of capital we have historically utilized are not available on acceptable terms, we may curtail our capital spending.

As we execute our business strategy, we will continually monitor the capital resources available to meet future financial obligations and planned capital expenditures.  We cannot make assurances that our business will generate sufficient cash flow from operations to service our outstanding indebtedness or that future borrowings will be available to us in an amount sufficient to enable us to pay our outstanding indebtedness or to fund our other capital needs.  If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such as, refinancing or restructuring our debt; selling assets; reducing or delaying acquisitions or our drilling programs; or seeking to raise additional capital.

We continue to evaluate our management of liability options and may in the future refinance our senior notes or engage in negotiations with holders of our senior notes or other debt holders regarding potential alternative transactions, along with possible avenues for increasing our near-term liquidity.

However, we cannot make assurances that any such negotiations will be successful or that we would be able to refinance or restructure our debt or implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that implementing any such alternative financing plans would allow us to meet our debt obligations.  In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.

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% at September 30, 2016. Interest is payable semi-annually each April 15th and October 15th. The senior notes are unsecured and are 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 that allows for retirement of the principal outstanding, in whole or in part, at 100.0% beginning on October 15, 2016. As of September 30, 2016, we were in compliance with all financial covenants of the senior notes.

Credit Facility 

On November 10, 2016, we amended and restated our senior secured revolving credit facility with Wells Fargo Bank, N.A. as the administrative agent, which now matures on April 14, 2018 and will be extended to November 10, 2020 subject to the completion of a refinancing or an extension of the maturity date of the 2018 Notes.  As of November 10, 2016, the credit facility was subject to a $300 million borrowing base limit. As of November 10, 2016, we had $70.6 million of outstanding borrowings and $7.6 million of outstanding letter of credit.  Our restricted subsidiaries are guarantors of the credit facility.

 The credit facility borrowing base is redetermined semi-annually in May and November. 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 (“LIBOR”) plus a margin ranging from 2.75% to 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the utilization of our borrowing base, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00, 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 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the utilization of our borrowing base, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00, depending on the utilization of our borrowing base. The average rate on all loans outstanding as of September 30, 2016 under the credit facility was 4.13%, which was based on the Eurodollar option.

The credit facility and the indenture governing the senior notes include covenants requiring us to maintain certain financial covenants including a current ratio and leverage ratio. The terms of the credit facility also restrict our ability to make distributions and investments.  At September 30, 2016, we were in compliance with the covenants. 

Senior Secured Term Loan

 On June 2, 2015, we entered into a second lien senior secured term loan agreement (the “Term Loan Facility”), which was subsequently amended on February 3, 2016, 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 matures on April 15, 2018. 

Borrowings under the Term Loan Facility bear interest at adjusted LIBOR plus 8.00%. 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 5.0 to 1.0 (decreasing to 4.5 to 1.0 for the quarter ended

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December 31, 2016), (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.  PV-9 is calculated using four year NYMEX strip pricing adjusted for differentials.  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, 2016, we were in compliance with the covenants of the Term Loan Facility.

On November 10, 2016, we used a portion of the contribution from our Class B partner to repay all amounts outstanding under the Term Loan Facility of $127.5 million, which includes a $2.5 million prepayment premium for repaying all amounts owed under the Term Loan Facility prior to maturity date.

 Cash flow provided by operating activities 

Operating activities provided cash of $7.5 million during the nine months ended September 30, 2016 as compared to cash provided by operating activities of $129.7 million during the comparable period in 2015, a decrease of $122.2 million.  The decrease in operating cash flows was attributable to various factors.  Cash-based items of net loss, 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 $22.6 million in the first nine months of 2016.    Changes in restricted cash, working capital and other assets and liabilities resulted in a decrease of $99.6 million in the first nine months of 2016 as compared to the corresponding period in 2015.

Cash flow used in investing activities 

Investing activities used cash of $147.8 million during the nine months ended September 30, 2016 as compared to $182.7 million during the comparable period of 2015.  Capital expenditures for property and equipment used cash of $149.2 million and $184.5 million in the first nine months of 2016 and 2015, respectively. Acquisitions used cash of $48.6 million in the first nine months of 2015.  Sales of properties provided proceeds of $1.4 million and $25.8 million in the first nine months of 2016 and 2015, respectively. During the fourth quarter 2014, we placed net proceeds from the sale of our remaining interest in the Hilltop field into a restricted cash account as required under the IRS Code Section 1031-Like-Kind Exchange. During the first nine months of 2015, net proceeds in the restricted account provided proceeds of $24.6 million. 

Cash flow provided by financing activities 

Financing activities provided cash of $139.6 million during the nine months ended September 30, 2016 as compared to $58.4 million during the comparable period in 2015.  During the first nine months of 2016 we drew down $141.9 million on our credit facility and deposited the cash in a controlled account pursuant to the Thirteenth Amendment of our credit facility.  In addition, we paid $0.8 million of deferred financing costs related to our credit facility.  In the first nine months of 2015, we received gross proceeds from the Term Loan Facility 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 Term Loan Facility.  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 partner 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 2015 Annual Report and Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 (“March 31, 2016 Form 10-Q”) and 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 2015 Annual Report and in our March 31, 2016 Form 10-Q. 

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 and have been trading at multi-year lows in the first nine months of 2016, 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  2015 Annual Report, the March 31, 2016 Form 10-Q 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 2015 Annual Report. There have been no material changes to the disclosure regarding market risks other than as noted below. See Part I, Item 1, Note 5 to our consolidated financial statements for a description of our outstanding derivative contracts at the most recent reporting date.

The fair value of our commodity derivative contracts at September 30, 2016 was a net liability of $3.5 million. A 10% increase or decrease in oil, natural gas and natural gas liquids 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 commodity derivative contracts of approximately $32.2 million (decrease in value) or $29.3 million (increase in value), respectively, as of September 30, 2016.  

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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 $2.9 million, based on the balance outstanding as of September 30, 2016.

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, 2016 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, 2016 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 2015 Annual Report and in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2016.  Except as set forth below, there have been no material changes with respect to the risk factors disclosed in such reports during the quarter ended September 30, 2016.  



A substantial portion of our producing properties are located in a limited geographic area, making us vulnerable to risks associated with having geographically concentrated operations.

A substantial portion of our producing properties are geographically concentrated in the STACK, with that area comprising approximately 63% of our oil and natural gas production and approximately 64% of our oil and natural gas revenues as of September 30, 2016. Approximately 92% of our estimated proved reserves were located in the STACK as of September 30, 2016.



Because of this concentration in limited geographic areas, the success and profitability of our operations may be disproportionately exposed to regional factors relative to our competitors that have more geographically dispersed operations. These factors include, among others: (i) the prices of crude oil and natural gas produced from wells in the regions and other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints; (ii) the availability of rigs, equipment, oil field services, supplies, and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operations in the STACK may be adversely affected by severe weather events such as floods, ice storms and tornadoes, which can intensify competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in limited geographic areas also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our financial condition, results of operations and cash flows.



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

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi‑year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop identified locations depends on a number of uncertainties, including oil, natural gas and NGLs prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are located, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

Furthermore, our estimate of the number of our net drilling locations is based on a number of assumptions, which may prove to be incorrect. For example, we have estimated the number of net drilling locations based on our expected working interests in each gross drilling location based on our existing working interest associated with our acreage applicable to such drilling location and any assumed dilution of such working interest based on any expected unitization of such acreage with adjacent properties controlled by third parties. Our assumptions regarding the impact on any such unitization on our working interest in our gross drilling locations may be incorrect and may result in more dilution of our working interest than anticipated, which would result in a reduction of our net drilling locations.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise the capital required. Any drilling activities we are able to conduct on these potential locations may not be successful or allow us to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing acreage.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. Although the majority of our reserves are located on leases that are held by production, we do have provisions in some of our leases that provide for the lease to expire unless certain conditions are met, such as drilling having commenced on the lease or production in paying quantities having been obtained within a defined time period. If commodity prices remain low or we are unable to fund our anticipated capital program, there is a risk that some of our existing proved reserves and some of our unproved inventory could be subject to lease expiration or a requirement to incur additional leasehold costs to extend the lease. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. This could result in a reduction in our reserves and our growth opportunities (or the incurrence of significant costs). Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGLs we produce.

The availability of a ready market for any oil, natural gas and NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. While we believe that we would be able to locate alternative purchasers, we cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.

The adoption of derivatives legislation and regulations by the U.S. Congress related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market.  Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

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In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on November 7, 2013, a proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. On May 27, 2016, the CFTC issued a proposed supplement to its 2013 position limits proposal, which is intended to modify the process by which a non-enumerated hedging transaction may be determined to be a “bona fide hedge” transaction, and thereby become exempt from the CFTC’s position limits. A final rule has not yet been issued. Similarly, the CFTC has issued a proposed rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a derivatives clearing organization and to trade all such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business.  The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which capital requirements rule could increase the costs to us of future financial derivatives transactions.  The Volcker Rule provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.

As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures.  Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.  Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations, or cash flows.

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

Hydraulic fracturing is used in many of our operations to stimulate production of hydrocarbons, particularly natural gas. Congress has, from time to time, considered legislation to amend the SDWA to remove the exemption currently available to hydraulic fracturing, which would place additional regulatory burdens upon hydraulic fracturing operations including requirements to obtain a permit prior to commencing operations adhering to certain construction requirements, to establish financial assurance, and to require reporting and disclosure of the chemicals used in those operations. This legislation has not passed.

Hydraulic fracturing is typically regulated by state oil and natural-gas commissions. However, several federal agencies have also asserted regulatory authority or pursued investigations over certain aspects of the process.  For example, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and issued a draft report in 2015 on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA’s Science Advisory Board provided its comments on the draft study, indicating its concern that the EPA’s conclusion of no widespread, systemic impacts on drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The final version of this EPA report remains pending.  In another example,

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the SDWA does not exempt hydraulic fracturing activities using diesel and, thus, the EPA has developed guidance for permitting of hydraulic fracturing activities using diesel.  Also, the Bureau of Land Management (“BLM”) adopted final rules in March 2015 regulating hydraulic fracturing on public lands which include requirements on drillers to disclose the chemicals used in hydraulic fracturing operations and new requirements for well casing, groundwater protections, and wastewater storage.  However, in September 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, and this decision remains on appeal.  In the event the rules are upheld, we are evaluating the impact of these rules on our operations.  Additionally, the EPA has announced an initiative under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals and, in June 2016, adopted regulations prohibiting discharges to publicly owned treatment works for certain wastewater generated by onshore unconventional oil and gas extraction facilities to publicly-owned treatment works.

In addition, some states, including Oklahoma where we operate, have adopted, and other states are considering adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. States could elect to prohibit high-volume hydraulic fracturing altogether, following the lead of the State of New York in 2015.  The issuance of any laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material adverse effect on our business, prospects, financial condition, results of operations, and liquidity.



We are subject to regulation under NSPS and NESHAP programs, which could result in increased operating costs.

In 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (the “NSPS”) and the National Emissions Standards for Hazardous Air Pollutants (the “NESHAP”) programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards required owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions.

The EPA issued new rules in June 2016 limiting methane emissions from new or modified oil and gas sources.  The rules amend the air emissions rules for the oil and natural gas sources and natural gas processing and transmission sources to include new standards for methane.  Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes.  In addition, the EPA had announced plans to begin work on regulations to regulate methane emissions from existing oil and gas sources.  Also, in January 2016, the BLM proposed rules governing flaring and venting on public and tribal lands, which could require additional equipment and emissions controls and well as inspection requirements.



Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

In recent years, the Obama administration’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for U.S. production activities and (4) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or proposed by current or future administrations or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

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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