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: March 31, 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 March 31, 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 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 March 31, 2016, and for the three months ended March 31, 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”). 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. 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.

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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.





3. PROPERTY AND EQUIPMENT



Property and equipment consists of the following (unaudited):  













4. 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 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 $127.1 million at March 31, 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 7 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

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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 $3.3 million were written down to their fair value of $1.5 million, resulting in an impairment charge of $1.8 million for the three months ended March 31, 2016.  For the three months ended March 31, 2015, oil and natural gas properties with a carrying amount of $272.0 million were written down to their fair value of $198.9 million, resulting in an impairment charge of $73.1 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 $0.3 million and $0.4 million in additions to asset retirement obligations measured at fair value during the three months ended March 31, 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 March 31, 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 5.  



5. 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 crude 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 7, 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. 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.

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

The following table summarizes the fair value (see Note 4 for further discussion of 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 March 31, 2016 (unaudited):  



OIL DERIVATIVE CONTRACTS













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We had the following open derivative contracts for natural gas at March 31, 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 March 31, 2016 (unaudited):



NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS





We had the following open financial basis swaps for natural gas at March 31, 2016 (unaudited):



BASIS SWAP DERIVATIVE CONTRACTS











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6. ASSET RETIREMENT OBLIGATIONS

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

 









7. 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”), (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 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 is recorded on our consolidated balance sheet under “Short-term restricted cash.”  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 2.00% and 2.75% or a “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The weighted average rate on outstanding borrowings was 3.38% as of March 31, 2016 and 2.87% as of December 31, 2015.  The letters of credit outstanding as of March 31, 2016 were $6,065,000.



The credit facility contains customary covenants including, among others, defined financial covenants, including minimum working capital levels (the ratio of current assets plus the unused borrowing base, to current liabilities, excluding assets and liabilities related to derivative contracts) of 1.0 to 1.0, minimum coverage of interest expense of 3.0 to 1.0, and maximum leverage of 4.00 to 1.00.  The interest coverage and leverage ratios refer to the ratio of earnings before interest, taxes, depreciation, depletion, amortization, and

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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 March 31, 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 Term Loan Facility includes an accordion feature which allows us to borrow up to an additional $50 million of additional term loans under the Term Loan Facility within one year following the closing, subject to certain conditions.  The net proceeds of approximately $121 million from the Term Loan Facility, after payment of transaction-related fees and expenses, were used to pay down our outstanding amounts under our existing credit facility.  The Term Loan Facility matures on April 15, 2018. The principal amount is payable at maturity. 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, (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 4.50 to 1.00 to 5.00 to 1.00.    



Borrowings under the Term Loan Facility bear interest at adjusted LIBOR plus 8%. The covenants in the Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) current assets to current liabilities of at least 1.0 to 1.0, (ii) debt to EBITDAX of no more than 4.5 to 1.0, (iii) PV-9 of total proved reserves to total secured debt of at least 1.5 to 1.0, and (iv) EBITDAX to interest expense of at least 2.5 to 1.0.  Obligations under the Term Loan Facility are guaranteed by certain of the Company’s subsidiaries and affiliates and are secured by second priority liens on substantially all of our subsidiaries assets that serve as collateral under the credit facility.  As of March 31, 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, and, if made prior to the first anniversary of the closing date, are also subject to a “make whole” premium to ensure that the lenders receive the total amount of interest that would have been paid from the date of prepayment to such first anniversary.

Senior Notes. We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective rate of 9.7825% at March 31, 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 $1.3 million and $1.4 million at March 31, 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 $26.0 million and $25.7 million at March 31, 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 may 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. 

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 11, 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

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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 $0.3 million for each of the three months ended March 31, 2016 and 2015. Such amounts have been added to the balance of the Founder Notes.

Deferred financing costs. As of March 31, 2016, the Company had $8.9 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 $7.1 million related to the Term Loan Facility and senior notes are netted with long-term debt on the consolidated balance sheet as of March 31, 2016 in accordance with ASU No. 2015-03, which we adopted in the fourth quarter of 2015.  Deferred financing costs of $1.8 million and $1.2 million related to the credit facility are included in deferred financing costs, net on the consolidated balance sheets at March 31, 2016 and December 31, 2015, respectively. Amortization of deferred financing costs recorded for the three months ended March 31, 2016 and 2015 was $0.9 million and $0.7 million, respectively. These costs are included in interest expense on the consolidated statements of operations.

8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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















9. 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 March 31, 2016 and December 31, 2015.

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any.  We have accrued a liability for groundwater contamination in Florida of $1.2 million and $1.3 million at March 31, 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 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

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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 March 31, 2016 and December 31, 2015, 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 initial stipulated value and the designated value of the PAR on the payment valuation date.  The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally intended to be either a recapitalization or an initial public offering of Company equity) or as selected by the participant, but no earlier than five years from the end of the year of the grant.  Both the initial designated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors. In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event.  After any payment valuation date, regardless of payment or none, vested PARs expire. During the first quarter of 2016,  we granted 360,000 new PARs with a SIDV of $40 and terminated 10,500 PARs with a SIDV of $40, resulting in 591,000 PARs issued at a weighted average of $36.87. 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 March 31, 2016 or December 31, 2015.

10. SIGNIFICANT RISKS AND UNCERTAINTIES

Our business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas were highly volatile during the years 2014 and 2015 and have declined dramatically since the second half of 2014 and remain depressed as of March 31, 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 and natural gas price derivative contracts.  See Note 5.

11. 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 limited partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture.

Distribution and Income Allocation: In connection with the recapitalization on March 25, 2014, our partnership agreement was amended and restated to provide, among other things, that all distributions under the partnership agreement shall first be made to 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 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 partnership agreement. A “Liquidity Event” is any event in which we receive cash proceeds

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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.



12. 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.











 



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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 our drilling efforts in our core properties in the Sooner Trend area of the Anadarko Basin in Oklahoma and the Weeks Island Area in South 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 revenue we generate from our operations will fluctuate based on, among other things:

•the prices at which we will sell our production;

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

•the level of our operating and administrative costs.

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

Substantially all of our oil and natural gas activities are conducted jointly with others and, accordingly, 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

Drillco Contract

On January 13, 2016, our wholly-owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “Joint Development Agreement”) with BCE-STACK Development LLC (“BCE”), to fund drilling operations in Kingfisher County, Oklahoma. The drilling program initially calls for the development of forty identified well locations, which will be developed in two tranches of twenty wells each. The parties may also mutually agree to additional tranches on the same terms as the initial tranches.

   

Under the Joint Development Agreement, BCE has committed to fund 100% of Oklahoma Energy’s working interest share of drilling and development costs for each well in which BCE 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’s working interest share of the drilling costs in such tranche exceeding such limit. We do not anticipate any such costs to be material. In exchange for the payment of drilling and completion costs, BCE 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’s achieving a 15% internal rate of return in a tranche, and further reduced to 7.5% of Oklahoma Energy’s initial interest upon BCE’s achieving a 25% internal rate of return. Upon the achievement of these return thresholds, the interest BCE relinquishes will be automatically assigned back to Oklahoma Energy. Following the completion of each Joint Well, BCE and Oklahoma Energy will bear their proportionate working interest share of all subsequent costs and expenses related to such Joint Wells.  

   

On March 8, 2016, the parties further agreed to add a third tranche of investment that will allow for the drilling of an additional 20 wells, representing an additional investment of up to $64 million. The terms and conditions are the same as those of the first two tranches.



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Drawdown under Credit Facility



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.  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 intended to be used for general corporate purposes.

Following the funding of this borrowing, the aggregate principal amount of borrowings under the credit facility was $300 million, including $6.1 million of outstanding letters of credit, with no remaining availability. These new borrowings bear interest at 3.25%.

Outlook, Market Conditions and Commodity Prices 

Our revenue, profitability and future growth depend on many factors, particularly the prices of oil and natural gas, 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 crisis; geopolitical activities, including developments in the Middle East, Ukraine, and South America; worldwide supply disruptions; 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 oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves, and our ability to finance operations, including the amount of our borrowing base under our credit facility.

During the last 12 month period ended March 31, 2016, NYMEX West Texas Intermediate (“NYMEX WTI”) oil prices ranged from a high of $59.83 per Bbl in June 2015 to a low of $30.62 per Bbl in February 2016.  During the first quarter of 2016, NYMEX WTI prices averaged approximately $33.45 per Bbl.  We received an average price of $30.51 per Bbl for the first 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 $2.89 per MMBtu in August 2015 to a low of $1.71 in March 2016. We received an average price of $1.73 per Mcf for natural gas in the first quarter of 2016 before the effects of hedging. The duration and magnitude of changes in oil and natural gas prices cannot be predicted.

Depressed oil and natural gas 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 $1.8 million and $73.1 million for the three months ended March 31, 2016 and 2015, respectively.  In the first quarter of 2016 and 2015, write-downs were primarily due to downward revisions in proved reserves in some fields and decreased prices for oil, natural gas and natural gas liquids.  In the first quarter of 2016, our impairments were primarily related to our natural gas fields in South Louisiana.  In the first quarter of 2015, our impairments were primarily related to Weeks Island Area and natural gas fields in East Texas and South Louisiana.  Further declines in oil and/or natural gas prices may result in additional impairment expenses.

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. 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 other 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 by 22% from $148 million for 2015 to $115 million for 2016.  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 and natural gas. Changes in these derivative assets and liabilities are reported in our consolidated statements of operations as gain / loss from 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 three months of 2016, we recognized a net gain on our derivative contracts of $10.8 million, which includes $25.2 million in cash settlements received on derivative contracts. The objective of our hedging program is that, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil and natural gas revenues will produce relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and we expect these gains and losses to continue to reflect changes in oil and natural gas prices.

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As of March 31, 2016, we have hedged approximately 72% of our forecasted production of proved developed producing reserves through 2019 at weighted average annual floor prices ranging from $2.88 per MMBtu to $4.50 per MMBtu for natural gas and $61.05 per Bbl to $67.05 per Bbl for oil.  If oil and/or natural gas 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 and natural gas 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 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.    Our assets in the Sooner Trend of Oklahoma are large, contiguous acreage blocks with multiple productive zones at depths generally between 4,000 feet and 8,000 feet.  These assets have historically been predominantly shallow-decline, long-lived oil fields originally drilled on 80-acre vertical well spacing and waterflooded to varying degrees.  Our focus in these fields is the continued implementation of a multi-year, multi-rig program to develop several pay zones with horizontal drilling and multi-stage hydraulic fracturing of the Mississippian age Osage, Meramec, and Manning and the Pennsylvanian age Oswego, as well as the definition of similar exploitation opportunities in the Woodford Shale, Hunton Lime, and other formations.    We also maintain production in the historically principal field pay zones that have been water flooded for several decades.  We have increased our acreage in the Sooner Trend to position ourselves for expanded horizontal development of stacked pays, both within and contiguous with our legacy position.  In the first quarter of 2016, we completed four horizontal wells in the Meramec formations in Sooner Trend. We had sixteen horizontal wells in progress as of the end of the first quarter of 2016,  eight of which were completed subsequent to quarter end.  Six of the wells in progress for the first quarter of 2016 were wells drilled as part of our Joint Development Agreement with BCE.

As of March 31, 2016, we had three drilling rigs operating in Sooner Trend for horizontal development and we plan to bring on one or two additional drillings rigs.  We plan to utilize up to five drilling rigs during 2016 targeting the Mississippian age Osage, Meramec, Manning, and the Pennsylvanian age Oswego with horizontal drilling.  We will also participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Osage. 

Production from our Sooner Trend properties in the first quarter of 2016 was approximately 11,000 BOE/Day net to our interest, 77% oil and natural gas liquids, as compared to approximately 7,720 BOE/Day, 80% oil and natural gas liquids, for the first quarter of 2015.

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

Weeks Island field, located in Iberia Parish, Louisiana, is a historically-prolific oil field with 55 potential pay zones that are structurally and stratigraphically trapped around a piercement salt dome.    We expect to continue development activity in this field in 2016.

Cote Blanche Island field is located near to Weeks Island in St. Mary Parish. The field is a salt dome structure and production from the Miocene sands was discovered in 1948 by Texaco, three years after the discovery at Weeks Island. 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. 

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 first quarter of 2016 was approximately 4,100 BOE/Day, net to our interest, 93% oil, as compared to 4,680 BOE/Day, 83% oil, for the first quarter of 2015.  Production from the Weeks Island  Area has remained above 4,000 BOE/Day, net to our interest, since November 2013.  





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Results of Operations: Three Months Ended March 31, 2016 v. Three Months Ended March 31, 2015





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Revenues

Oil revenues for the three months ended March 31, 2016, decreased $18.2 million, or 37%,  to $31.2 million from $49.4 million for the corresponding period in 2015. The decrease in revenue was primarily attributable to a decrease in average price and a decrease in production during the first quarter of 2016.   The average price of oil exclusive of settlements of derivative contracts decreased $15.80 per Bbl or 34% in the first quarter of 2016 compared to the first quarter of 2015, resulting in a decrease in oil revenues of approximately $16.2 million.  The overall price including settlements of derivative contracts decreased 29% from $74.96 per Bbl in the first quarter of 2015 to $53.21 per Bbl in the first quarter of 2016.    Production decreased 43 MBbls,  resulting in a decrease of $2.0 million in oil revenues.  The decrease in production is primarily due to the sale of our Eagleville field in 2015 of 190 MBbls partially offset by an increase in production in the Sooner Trend of 156 MBbls.

Natural gas revenues for the three months ended March 31, 2016 decreased $3.6 million, or 43%, to $4.6 million from $8.2 million for the same period in 2015. The decrease in natural gas revenue was primarily attributable to a decrease in average price and a decrease in production during the first quarter of 2016. The average price of natural gas exclusive of settlements of derivative contracts decreased $1.16 per Mcf or 40% in the first quarter of 2016, resulting in a decrease in natural gas revenues of approximately $3.2 million.  The overall price including settlements of derivative contracts decreased 39% from $3.99 per Mcf in the first quarter of 2015 to $2.44 per Mcf in the first quarter of 2016.  Production decreased 0.1 Bcf resulting in a decrease of $0.4 million in natural gas revenues. This decline is primarily due to an emphasis on liquids-rich assets in our portfolio. 

Natural gas liquids revenues decreased $0.6 million, or 21%, during the first quarter of 2016 to $2.1 million from $2.7 million in the same period in 2015. The decrease in natural gas liquids revenue was attributable to a lower average price during the first quarter of 2016, partially offset by increased production volumes.    The average price of natural gas liquids exclusive of settlements of derivative contracts decreased $5.25 per barrel or 32% in the first quarter of 2016 compared to the first quarter of 2015, resulting in a decrease in natural gas liquids revenues of $1.0 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 settlements of derivative contracts decreased 31% from $16.24 per Bbl in the first quarter of 2015 to $11.26 per Bbl in the first quarter of 2016.  Production increased 27 MBbls resulting in an increase of $0.4 million in natural gas liquids revenues.  The increase in production is primarily due to an increase in production in our Sooner Trend field of 60 MBbls partially offset by a decrease in production from the sale of our Eagleville field in 2015.

Other revenues decreased $0.1 million during the three months ended March 31, 2016 as compared to the three months ended March 31, 2015.  The revenue is related to pipeline and processing fees from our East Texas properties.

Gain on sale of assets was $2.6 million for the first quarter of 2016 as compared to a gain of $0.1 million for the first quarter of 2015.    The gain recorded in the first quarter of 2016 is primarily related to the sale of non-core assets in Southeast Louisiana.



Gain on derivative contracts was a gain of $10.8 million during the three months ended March 31, 2016 as compared to a gain of $26.8 million during the same period in 2015. The change from period to period is due to the decrease in oil and natural gas prices and changes in our derivative contracts during these periods.    Settlements of commodity contracts decreased $8.5 million in the first quarter of 2016 as compared to the first quarter of 2015.

Expenses

Lease and plant operating expense increased $0.1 million or 1% in the first quarter of 2016 as compared to the first quarter of 2015, to $18.5 million from $18.4 million.  In general, there was an increase in field services and marketing and gathering expense of approximately $1.4 million partially offset by a decrease in repairs and maintenance and chemical, fuel and utilities expense of $1.3  million. On a per unit basis, lease and plant operating expense  was  $11.12 per BOE and $10.77 per BOE for the first quarter 2016 and 2015, respectively.    

Production and ad valorem taxes decreased $1.9 million, or 44%, to $2.4 million for the first quarter of 2016, as compared to $4.3 million for the first quarter of 2015.  Production taxes decreased from $3.2 million for the first quarter of 2015 to $2.1 million for the first quarter of 2016,  primarily due to the decline in oil revenues.  Ad valorem taxes decreased $0.8 million for the first quarter of 2016 as compared to the first quarter of 2015 due to the sale of our Eagleville field in 2015 and a decrease in taxable values. 

Workover expense decreased $1.9 million during the first quarter of 2016, as compared to the first quarter of 2015. This expense varies depending on activities in the field and is attributable to many different properties.

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 decreased from $24.5 million for the first quarter of 2015 to $3.3 million for the first quarter of 2016, primarily due to a decrease in dry hole expense of $18.2 million and geologic and geophysical (“G&G”)  seismic expense of $3.1 million in the first quarter of 2016 as compared to the first quarter of

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2015.    During the first quarter of 2016, exploration expense consisted of dry hole expense of $0.2 million, G&G seismic expense of $1.2 million, expired leases of $1.2 million and plug and other abandonment expenses of $0.5 million.

Depreciation, depletion and amortization decreased from $40.7 million for the first quarter of 2015 to $21.5 million for the first quarter of 2016. On a per unit basis, this expense decreased from $23.84 per BOE in the first quarter of 2015 to $12.89 per BOE in the first quarter of 2016.  The 2016 depletion rate per BOE was lower due to the impairment of proved properties in 2015, 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 $73.1 million in the first quarter of 2015 to $1.8 million in the first 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 first quarter of 2016 included a write-down of natural gas fields in South Louisiana of $1.4 million.

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 each of the first quarters of 2016 and 2015. 

General and administrative expense decreased $7.5 million for the first quarter of 2016 to $10.2 million from $17.7 million for the first quarter of 2015.  The decrease is primarily due to a decrease in salary, benefits and performance bonus of $2.8 million and a decrease in accrued settlement expense related to litigation of $4.9 million partially offset by an increase in legal fees of $1.1 million.  On a per unit basis, general and administrative expenses were $6.11 per BOE and $10.36 per BOE for the first quarters of 2016 and 2015, respectively.

Interest expense, net increased from $14.1 million for the first  quarter of 2015 to $16.2 million for the  first quarter of 2016.  The increase is primarily due to interest incurred on the second lien senior secured term loan of $2.7 million that we entered into during the second quarter of 2015, partially offset by decreased  interest on our credit facility of $0.8 million due to a lower average balance outstanding.    

Liquidity and Capital Resources 

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

Our 2016 capital budget is primarily focused on the development of existing core areas through exploitation and development. Currently, we plan to spend approximately $115 million in 2016 for exploration and development, of which 91% is allocated to our Sooner Trend properties and  the Weeks Island Area.  We have expended or accrued approximately $41.3 million through March 31, 2016.    We reduced our anticipated capital expenditures for 2016 from 2015 levels in response to the significant decline in oil prices since the third quarter of 2014 and in order to preserve liquidity.  Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. Because a large percentage of our acreage is held by production, we have the ability to materially decrease our drilling and recompletion budget in response to market conditions with decreased risk of losing significant acreage.

We expect to fund our 2016 capital expenditures predominantly with cash flows from operations, 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 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 assure you 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.

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We continue to evaluate our liability management options and may in the future 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 assure you 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%. 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 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.

Credit Facility 

We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent, which matures October 13, 2017.  As of March 31, 2016, the credit facility was subject to a $300 million borrowing base limit.  We had $300 million outstanding under the credit facility at March 31, 2016, which includes $293.9 million of outstanding borrowings and $6.1 million of outstanding letters of credit. Our restricted subsidiaries are guarantors of the credit facility.

On February 3, 2016, we entered into an Agreement and Amendment No. 13 (the “Thirteenth Amendment”) to the credit facility which, 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, (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 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. Such funds will not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account. As of May 13, 2016 the outstanding borrowing under the credit facility was $300 million, including $293.9 million of outstanding borrowings and $6.1 million of outstanding letters of credit, with no remaining availability. These new borrowings bear interest at 3.25%.  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 2.00% to 2.75%, depending on the utilization of our borrowing base. “Reference rate” loans accrue interest at the prime rate of Wells Fargo Bank, N.A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The average rate on all loans outstanding as of March 31, 2016 under the credit facility was 3.38%, which was based on the Eurodollar option.

The credit facility, the indenture governing the senior notes and the senior secured term loan facility include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At March 31, 2016, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.

Senior Secured Term Loan

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

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

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and natural gas properties pursuant to the joint development agreement with BCE, (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 4.50 to 1.00 to 5.00 to 1.00.    

Borrowings under the Term Loan Facility bear interest at adjusted LIBOR plus 8%. The covenants in the Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) current assets to current liabilities of at least 1.0 to 1.0, (ii) debt to EBITDAX of no more than 4.5 to 1.0, (iii) PV-9 of total proved reserves to total secured debt of at least 1.5 to 1.0, and (iv) EBITDAX to interest expense of at least 2.5 to 1.0.  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 March 31, 2016, we were in compliance with the covenants of the Term Loan Facility.

We have the option to prepay all or a portion of the Term Loan Facility at any time, and we are subject to certain mandatory prepayments of proceeds from asset sales or an initial public offering, which are subject to certain prepayment premiums.  

Cash flow provided by (used in) operating activities 

Operating activities used cash of $101.8 million during the three months ended March 31, 2016 as compared to cash provided by operating activities of $58.4 million during the comparable period in 2015, a decrease of $160.2 million.  The decrease in operating cash flows was attributable to various factors.  Cash-based items of net income, including revenues (exclusive of  unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net decrease of approximately $17.7 million.    Changes in restricted cash, working capital and other assets and liabilities resulted in a decrease of $142.5 million in the first three months of 2016 as compared to the corresponding period in 2015.

Cash flow used in investing activities 

Investing activities used cash of $44.4 million during the three months ended March 31, 2016 as compared to $45.5 million during the comparable period of 2015.  Capital expenditures for property and equipment used cash of $44.4 million and $95.6 million in the first three months of 2016 and 2015, respectively. Sales of properties provided proceeds of $25.5 million in the first three months of 2015.  During the fourth quarter of 2014, we sold our remaining interests in the Hilltop field and placed the net proceeds into a restricted cash account with a qualified intermediary available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code.  During the first quarter of 2015, net proceeds in the restricted account provided proceeds of $24.6 million.    

Cash flow provided by (used in) financing activities 

Financing activities provided cash of $141.1 million during the three months ended March 31, 2016 as compared to cash used by financing of $9.5 million during the comparable period in 2015.  During the first quarter 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 quarter of 2015, we made payments of $30.0 million to reduce the balance under our credit facility partially offset by draws made on our credit facility of $21.0 million. We made a capital distribution of $0.5 million during the first 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 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.  

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 quarter 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 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 oil and natural gas derivative contracts at March 31, 2016 was a net asset of $89.9 million. A 10% increase or decrease in oil and natural gas prices with all other factors held constant would result in a decrease or increase, respectively, in the estimated fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts of approximately $20.2 million (decrease in value) or $20.8 million (increase in value), respectively, as of March 31, 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 March 31, 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 March 31, 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 March 31, 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 9 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.  Except as set forth below, there have been no material changes with respect to the risk factors disclosed in the 2015 Annual Report during the quarter ended March 31, 2016.  

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 the 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. 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.

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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