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, 2017

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, a smaller reporting company or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.☐ 

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 exploration and production company engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties.   Our principal area of operation is in the eastern portion of the Anadarko Basin referred to as the STACK.  The STACK is an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked productive formations present in the area.  Our operations also include other oil and natural gas interests in Texas, Louisiana and Florida.



2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We have provided a discussion of significant accounting policies in Note 2 in our Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Annual Report”).  As of March 31, 2017,  our significant accounting policies are consistent with those discussed in Note 2 in the 2016 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, 2016, which were filed with the Securities and Exchange Commission in our 2016 Annual Report.

The consolidated financial statements included herein as of March 31, 2017, and for the three months ended March 31, 2017 and 2016, 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 FASB issued ASU No. 2014-09, Revenue from Contracts with Customers.  The update provides guidance concerning the recognition, measurement and disclosure 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 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 deferred 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.  The Company has not yet selected a transition method and is currently assessing the impact on the consolidated financial statements.  The Company is continuing to evaluate the provisions of this ASU as it relates to certain sales contracts and in particular as it relates to disclosure requirements.   

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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 enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services and equipment.  The Company continues to evaluate the impacts of the amendments to our financial statements and accounting practices for leases.  We anticipate adoption of ASU 2016-02 effective January 1, 2019.



In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.



In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash, which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.

  

In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business, which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 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.



3. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:











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4.  PROPERTY AND EQUIPMENT



Property and equipment consists of the following (unaudited):  





















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 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 and we estimate the fair value of the senior notes for disclosure purposes. We have estimated the fair value of our $500 million senior notes payable to be $511.3 million at March 31, 2017.  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, natural gas and natural gas liquids 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, natural gas and natural gas liquids 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 $3.4 million were written down to their fair value of $2.2 million, resulting in an impairment charge of $1.2 million for the three months ended March 31, 2017.  For the three months ended March 31, 2016, 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. 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

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timing of plugging and abandonment of wells and facilities. We recorded $0.3 million and $0.3 million in additions to asset retirement obligations measured at fair value during the three months ended March 31, 2017 and 2016, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2017 and December 31, 2016, 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 senior secured revolving 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 senior secured revolving 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 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 a derivative 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:



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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 senior secured revolving 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, 2017 (unaudited):  



OIL DERIVATIVE CONTRACTS













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We had the following open derivative contracts for natural gas at March 31, 2017 (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, 2017 (unaudited):



NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS





We had the following open financial basis swap contracts for natural gas March 31, 2017 (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):  

 





Senior Secured Revolving Credit Facility.    In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks.  As of March 31, 2017, we had $95.7 million outstanding with $184.2 million of available borrowing capacity under the credit facility.  The borrowing base is currently $287.5 million and the principal amount is payable on the maturity date of November 10, 2020.  The credit facility borrowing base is redetermined semi-annually in May and November of each year.  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. We have a choice of borrowing in Eurodollars or at the “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, National Association.  The credit facility bears interest at the London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00.  The reference rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, 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 percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00.  The weighted average and effective interest rate on outstanding borrowings was 4.48% as of March 31, 2017 and 4.00% as of December 31, 2016.  The letters of credit outstanding as of March 31, 2017 and December 31, 2016 were approximately $7.6 million.



The credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment amounts available under the credit facility are at least 20% of the commitments in effect.

The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest,

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taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0.



As of March 31, 2017, we were in compliance with all financial covenants of the credit facility. 

Senior Unsecured Notes. We have $500 million in aggregate principal amount of 7.875% senior unsecured notes (“2024 Notes”) due December 15, 2024 which were issued at par by the Company and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016.  Interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the 2024 Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2024 Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the 2024 Notes for cash at a redemption price equal to 100% of their principal amount of the 2024 Notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the 2024 Notes may require us to repurchase all or a portion of the 2024 Notes for cash at a price equal to 101% of the aggregate principal amount of the 2024 Notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the 2024 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.

The 2024 Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the 2024 Notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the 2024 Notes.

The 2024 Notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business. 

Under the terms of the indenture for the 2024 Notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their 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.

The indenture governing the 2024 Notes includes covenants requiring us to maintain certain financial covenants including a current ratio and leverage ratio.  As of March 31, 2017, we were in compliance with all financial covenants of the 2024 Notes. 

Notes Payable to Founder. We have notes payable to our founder (“Founder Notes”) that bear simple interest at 10% with a balance of $27.3 million and $27.0 million at March 31, 2017 and December 31, 2016, 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 of High Mesa. 

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 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, 2017 and 2016.  Such amounts have been added to the balance of the Founder Notes.

Deferred financing costs. As of March 31, 2017,  we had $12.8 million of deferred financing costs related to the senior secured revolving credit facility and senior notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $10.4 million related to the senior notes are netted with long-term debt on the consolidated balance sheet as of March 31, 2017.  Deferred financing costs of $2.4 million related to the credit facility are included in deferred financing costs, net on

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the consolidated balance sheets at March 31, 2017. Amortization of deferred financing costs recorded for the three months ended March 31, 2017 and 2016 was $1.0 million and $0.9 million, respectively.  These costs are included in interest expense on the consolidated statements of operations.

The credit facility and the 2024 Notes contain customary events of default.  If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest.  Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. 

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 March 31, 2017.

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 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, 2017, we have accrued approximately $3.2 million ($0.8 million in current liabilities and $2.4 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.

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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 can be construed in accordance with the meaning of the term “change in control event”) 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 three months of 2017,  we granted 306,300 new PARs with a SIDV of $40 and terminated 500 PARs with a SIDV of $40, resulting in 881,100 PARs issued at a weighted average of $37.90 as of March 31, 2017. 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, 2017 or December 31, 2016.

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.  Although oil and natural gas prices have recently begun to recover from lows experienced since the decline in the second half of 2014, forecasted prices for both oil and natural gas continue to remain depressed.  The duration and magnitude of changes in oil and natural gas prices cannot be predicted.  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 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.  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’ CAPITAL

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 sole 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. 

In connection with the sale of Series E preferred stock by our Class B partner, on February 24, 2017, our General Partner, High Mesa and all of our Class A limited partners entered into a Fifth Amended and Restated Limited Partnership Agreement, and the owners of the General Partner entered into a Fourth Amended and Restated Limited Liability Company Agreement to provide for the Series E preferred stock in the distribution formula and certain other provisions of the amended agreements.

Contribution, Distribution and Income Allocation:  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 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 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 partnership agreement.  A “Liquidity Event” is defined as the first to occur, in one or a series of related transactions, of (i) a disposition of all or substantially of the assets of High Mesa and its subsidiaries to a person that is not an affiliate of High Mesa, (ii) a disposition of all the equity securities of High Mesa, or (iii) the consummation of a public offering of the common equity securities of High Mesa or any of its subsidiaries that hold all of substantially all of High Mesa’s assets on a consolidated basis, and if the public offering is of a subsidiary of High Mesa, the subsequent distribution of the public company equity securities or proceeds obtained in the public offering to the holders of equity securities of High Mesa.  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.

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On December 31, 2016, High Mesa purchased from BCE-STACK Development LLC and contributed interest in 24 producing wells drilled under the joint development agreement to us.  High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected during the first quarter of 2017.  There were no contributions during the first quarter of 2016. 



13. SUBSIDIARY GUARANTORS

All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes and our credit 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 and 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, 2016 (“2016 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 2016 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 STACK.  We have transitioned our focus from our diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities.  The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and historically high drilling success rates.  We maintain operational control of the majority of our properties, either through directly operating them, or through operating arrangements with minority interest holders.  

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, natural gas and natural gas liquids 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 price volatility on our cash flows.

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

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.  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 senior secured revolving credit facility.

During the last twelve month period ended March 31, 2017, NYMEX West Texas Intermediate (“NYMEX WTI”) oil prices ranged from a high of $53.46 per Bbl in February 2017 to a low of $41.12 per Bbl in April 2016.  During the first quarter of 2017, NYMEX WTI prices averaged approximately $51.91 per Bbl compared to $33.45 per Bbl for the same period of 2016.  We received an average price of $49.62 per Bbl for the first quarter of 2017 before the effects of hedging.  NYMEX Henry Hub natural gas prices (“NYMEX HH”) have also been volatile and ranged from a high of $3.93 per MMBtu in January 2017 to a low of $1.90 in April 2016. We received an average price of $2.94 per Mcf for natural gas in the first quarter of 2017 before the effects of hedging.  As of May 2, 2017, NYMEX WTI was $47.66 per Bbl and NYMEX Henry Hub was $3.20.  Commodity prices remain volatile and unpredictable but have improved during 2017 compared to the first quarter of 2016. 

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We have increased our anticipated capital expenditures, including acquisitions, for 2017 to $290 million, which is 28% over the $226 million of capital expenditures, including acquisitions spent in 2016.  Additionally, we anticipate that up to an additional $101 million will be funded for 2017 drilling and completions activity in the STACK by BCE-STACK Development LLC (“BCE”) pursuant to our joint development agreement.  We have allocated approximately 95% of our 2017 capital expenditure to develop the STACK.  We anticipate operating up to eight drilling rigs by the end of 2017, which will result in drilling a total of approximately 150 gross wells in the STACK. Of the total anticipated gross wells to be drilled in 2017, we plan to drill approximately 42 gross wells as part of our joint development agreement with BCE.

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 three months of 2017, we recognized a net gain on our derivative contracts of $30.2 million, which includes $2.0 million in cash settlements paid 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, 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 March 31, 2017, we have hedged approximately 60%  of our forecasted production of proved developed producing reserves through 2019 at weighted average annual floor prices ranging from $3.14 per MMBtu to $4.50 per MMBtu for natural gas and $49.53 per Bbl to $51.67 per Bbl for oil.  If oil, natural gas and natural gas liquids prices 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. 

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 $1.2 million and $1.8 million for the three months ended March 31, 2017 and 2016, respectively.  In the first quarter of 2017 and 2016, 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 quarter of 2017, our impairments were primarily related to our non-core areas.  Further declines in oil and/or natural gas prices may result in additional impairment expenses.

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 and 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 

STACK, Oklahoma.    Our STACK 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 located at total vertical 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.   

In the first quarter of 2017, we brought twenty-nine horizontal wells on production in the Osage and Meramec formations in the STACK.  Sixteen of the wells we brought on production during the first quarter of 2017 were funded through of our joint development agreement with BCE.  We had thirty-three horizontal wells in progress as of the end of the first quarter of 2017,  thirteen of which were funded through our joint development agreement with BCE.  Nine of the thirty-three horizontal wells in progress as of March 31, 2017, were on production subsequent to quarter end. 

As of March 31, 2017, we had six drilling rigs operating in the STACK.  We plan to continue targeting the Mississippian-age Osage, Meramec, and Manning formations and the Pennsylvanian-age Oswego formation with horizontal drilling.  We will also participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Osage.  

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Production from our STACK assets in the first quarter of 2017 was an average of approximately 19,300 BOE/day net to our interest, 70% oil and natural gas liquids, as compared to an average of approximately 11,000 BOE/day, 77% oil and natural gas liquids, in the first quarter of 2016.

Weeks Island Area.    The Weeks Island Area, located in Iberia and St. Mary Parish, Louisiana, contains our most significant conventional proved developed oil reserves and consists of the Weeks Island and Cote Blanche Island fields. The 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, which we believe offer significant future opportunities for added production and reserves.  The Cote Blanche Island field, located near the Weeks Island field in St. Mary Parish, is also a salt dome structure.  The geology is similar to the Weeks Island field, and we anticipate that the same geologic interpretation methods and engineering development techniques could be utilized at the Cote Blanche field that were used at the Weeks Island field to increase reserves and production. 

Production from the Weeks Island Area in the first quarter of 2017 was approximately 2,300 BOE/day, net to our interest, 96% oil, as compared to 4,100 BOE/day, 93% oil, for the first quarter of 2016. 



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Results of Operations: Three Months Ended March 31,  2017 v. Three Months Ended March 31, 2016





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Revenues

Oil revenues in the three months ended March 31, 2017 increased $28.1 million, or 90%,  to $59.3 million from $31.2 million in the corresponding period in 2016. The increase in revenue was primarily attributable to an increase in average price as well as  an increase in production during the first quarter of 2017.   The average price of oil exclusive of derivative contract settlements increased  $19.11 per Bbl or 63% in the first quarter of 2017 compared to the first quarter of 2016, resulting in an increase in oil revenues of approximately $22.8 million. When including the effects of derivative contract settlements, the overall price decreased 9% from $53.21 per Bbl in the first quarter of 2016 to $48.28 per Bbl in the first quarter of 2017.  Production increased 172 MBbls,  resulting in an increase of $5.3 million in oil revenues.  The oil production volume increase is primarily due to new production from wells coming online in the STACK of 338 MBbls, partially offset by a decrease in production in the Weeks Island Area of 153 MBbls due to natural decline in production.

Natural gas revenues in the three months ended March 31, 2017 increased $8.0 million, or 170%, to $12.7 million from $4.7 million in the same period of 2016. The increase in natural gas revenue was primarily attributable to an increase in average price as well as an increase in production during the first quarter of 2017.  The average price of natural gas exclusive of derivative contract settlements increased $1.21 per Mcf in the first quarter of 2017, resulting in an increase in natural gas revenues of approximately $5.2 million.  When including the effects of derivative contract settlements, the overall price increased 19% from $2.44 per Mcf in the first quarter of 2016 to $2.91 per Mcf in the first quarter of 2017.  Production increased 1.6 Bcf resulting in an increase of $2.8 million in natural gas revenues. The natural gas volume increase is primarily due to new production from wells coming online in the STACK as natural gas is produced in association with oil. 

Natural gas liquids revenues increased $5.5 million, or 262%, during the first quarter of 2017 to $7.6 million from $2.1 million in the same period in 2016. The increase in natural gas liquids revenue was attributable to an increase in higher average price as well as an increase in processed volumes during the first quarter of 2017.  The average price of natural gas liquids exclusive of derivative contract settlements increased $14.09 per Bbl or 128% in the first quarter of 2017 compared to the first quarter of 2016, resulting in an increase in natural gas liquids revenues of $4.3 million.  The overall price including derivative contract settlements increased 116% from $11.26 per Bbl in the first quarter of 2016 to $24.32 per Bbl in the first quarter of 2017.    Production increased 112 MBbls  from 192 MBbls to 304 MBbls, resulting in an increase of $1.2 million in natural gas liquids revenues. The natural gas liquids volume is predominately in the STACK where natural gas liquid processed volumes increased 106 MBbls. 

Gain on sale of assets was a gain of $2.6 million in the first quarter of 2016, primarily related to the sale of non-core assets in Southeast Louisiana.

Gain on derivative contracts was a gain of $30.2 million in the first quarter of 2017 as compared to a gain of $10.8 million during the same period in 2016.  The fluctuation from period to period is due to the volatility of oil,  natural gas and natural gas liquids prices and changes in our outstanding hedge contracts during these periods.    

Expenses

Lease and plant operating expense increased $0.6 million or 4% in the first quarter of 2017 as compared to the first quarter of 2016, to $17.7 million from $17.1 million.  In general, there was an increase in compression, repairs and maintenance and salt water disposal costs of $2.0 million partially offset by a decrease in field services and rental equipment of $1.4 million.  On a per unit basis, lease and plant operating expense  was  $7.99 per BOE and $10.27 per BOE in the first quarters  of 2017 and 2016, respectively.  The lease and plant operating expense on a per unit basis was lower in the first quarter of 2017 as compared to the first quarter of 2016 primarily due to an increase in production volumes while lease and plant operating expense remained relatively flat quarter over quarter.    

Marketing and transportation expense increased $4.6 million to $6.0 million in the first quarter of 2017 as compared to $1.4 million in the first quarter of 2016.  The increase is primarily due to increased throughput for our properties in the STACK at the Kingfisher Midstream, LLC (“KFM”)  processing facility commissioned during the second quarter of 2016.  In addition, the increase is due to a higher marketing and transportation fee charged for utilizing a more efficient facility at the KFM plant.  On a per unit basis, marketing and transportation expense was $2.72 per BOE and $0.85 per BOE in the first quarters of 2017 and 2016, respectively.

Production and ad valorem taxes increased $0.7 million, or 28%, to $3.1 million in the first quarter of 2017, as compared to $2.4 million in the first quarter of 2016.  The increase is primarily due to an increase in production taxes as a result of the increase in oil and natural gas revenues.  Production taxes increased from $2.1 million for the first quarter of 2016 to $2.7 million for the first quarter of 2017. 

Workover expense was $1.4 million for each of the first quarters of 2017 and 2016. 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 increased from $3.3 million in the first

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quarter of 2016 to $8.1 million in the first quarter of 2017,  primarily due to an increase in expired leasehold and settlements of our asset retirement obligation in excess of our estimate of $4.3 million, and an increase in geologic and geophysical (“G&G”)  seismic expense of $0.7 million partially offset by a decrease in dry hole of $0.2 million.

Depreciation, depletion and amortization expense increased from $21.5 million in the first quarter of 2016 to $24.8 million in the first quarter of 2017. On a per unit basis, this expense decreased from $12.89 per BOE in the first quarter of 2016 to $11.18 per BOE in the first quarter of 2017.   Depreciation, depletion, and amortization is a function of capitalized costs of proved properties, proved reserves and production by field.  In addition, the impairment of proved properties in 2015 and the first half of 2016 lowered the depletable base and rate in the first quarter of 2017.  Furthermore, an increase in proved reserves contributed to the lower depletion rate in the first quarter of 2017.

Impairment expense decreased from $1.8 million in the first quarter of 2016 to $1.2 million in the first quarter of 2017. This expense varies with the results of exploratory and development drilling, as well as with well performance, declines in commodity price and other factors that may render some fields uneconomic, resulting in impairment.  Impairment expense in the first quarter of 2017 and 2016 were write-downs in non-core 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 $0.6 million for the first quarter of 2017 and $0.5 million for the first quarter of 2016. 

General and administrative expense decreased $0.5 million in the first quarter of 2017 to $9.7 million from $10.2 million in the first quarter of 2016.  The decrease is primarily due to lower legal fees of $1.5 million, partially offset by an increase in information system and engineering consulting fees of $1.1 million.  On a per unit basis, general and administrative expenses were $4.39 per BOE and $6.11 per BOE in the first quarters of 2017 and 2016, respectively.    General and administrative expenses on a per unit basis was lower in the first quarter of 2017 as compared to the first quarter of 2016 primarily due to an increase in production volumes while general and administrative expense remained relatively flat quarter over quarter.

Interest expense, net decreased from $16.2 million in the first quarter of 2016 to $12.1 million in the  first quarter of 2017. Interest on our senior secured revolving credit facility decreased $0.4 million due to a lower outstanding balance and interest on our senior secured term loan decreased $2.7 million as we retired our $125 million secured term loan facility during the fourth quarter of 2016.  In addition, interest on our senior unsecured notes decreased $1.1 million due to the refinancing of our $450 million aggregate principal amount of 9.625% senior unsecured notes due 2018 by issuing $500 million aggregate principal amount of 7.875% senior unsecured notes due 2024.

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 2017 capital budget is primarily focused on the development of our STACK play.  Currently, we plan to spend approximately $290 million in 2017, which includes acquisitions, of which over 95% is allocated to develop our STACK properties.  Additionally, we anticipate that up to an additional $101 million will be funded for 2017 drilling and completions activity in the STACK by BCE pursuant to our joint development agreement.  We have expended approximately $60.6 million of our capital budget through March 31, 2017.    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, natural gas and natural gas liquids 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. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production, revenues and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations.  However, 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.  In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

We expect to fund our 2017 capital budget predominantly with cash flows from operations, drilling and completion capital funded through our joint development agreement with BCE, and borrowings under our senior secured revolving 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

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selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

As we execute our business strategy, we will continually monitor the capital resources available to meet future financial obligations and planned capital expenditures.  We believe our cash flows provided by operating activities, cash on hand and availability under our senior secured revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2017 development drilling activities.  However, future cash flows are subject to a number of variables, including the level of oil, natural gas and natural gas liquids production and prices, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties.  We cannot make assurances that operational and other needed capital will be available on acceptable terms, or at all. 

Senior Unsecured Notes

We have $500 million in aggregate principal amount of 7.875% senior unsecured notes (the “2024 Notes”) due December 15, 2024 that was issued at par during the fourth quarter of 2016.  Interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the 2024 Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2024 Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the 2024 Notes for cash at a redemption price equal to 100% of their principal amount of the 2024 Notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the 2024 Notes may require us to repurchase all or a portion of the 2024 Notes for cash at a price equal to 101% of the aggregate principal amount of the 2024 Notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the 2024 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.

The 2024 Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the 2024 Notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the 2024 Notes.

The 2024 Notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business. 

The indenture contains customary events of default, including:  

The indenture governing the 2024 Notes includes covenants requiring us to maintain certain financial covenants including a current ratio and leverage ratio.  At March 31, 2017, we were in compliance with the covenants.

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Senior Secured Revolving Credit Facility 

We have a $750 million senior secured revolving credit facility currently subject to a $287.5 million borrowing base limit with Wells Fargo Bank, National Association as the administrative agent. Our senior secured revolving credit facility does not permit us to borrow funds if at the time of such borrowing, after giving pro forma effect to the application of funds from the borrowing, we have in deposit accounts available cash in excess of $25 million. Our senior secured revolving credit facility also does not permit us to borrow funds if at the time of such borrowing we are not in pro forma compliance with our financial covenants.

 

As of March 31, 2017, we have borrowed $95.7 million under the senior secured revolving credit facility and have $7.6 million of outstanding letters of credit reimbursement obligations.

Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest, payable quarterly. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the rate appearing on the Reuters Reference LIBOR01 page as the London Interbank Offered Rate (“LIBOR”), for deposits in dollars at 11:00 a.m. (London, England time) for one, three, or six months plus an applicable margin ranging from 275 to 375 basis points if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 300 to 400 basis points if our leverage ratio exceeds 3.25 to 1.00. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus an applicable margin ranging from 175 to 275 basis points if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 200 to 300 basis points if our leverage ratio exceeds 3.25 to 1.00. The next scheduled redetermination of our borrowing base is on May 1, 2017. Our borrowing base may be reduced in connection with the next redetermination of our borrowing base. The amounts outstanding under our senior secured revolving credit facility are secured by first priority liens on substantially all of our oil and natural gas properties and associated assets and all of the stock of our material operating subsidiaries that are guarantors of our senior secured revolving credit facility. If an event of default occurs under our senior secured revolving credit facility, the administrative agent will have the right to proceed against the pledged capital stock and take control of substantially all of our and our material operating subsidiaries that are guarantors’ assets.

Our senior secured revolving credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. Our senior secured revolving credit facility permits us to make distributions in any fiscal quarter so long as the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, no event of default exists, before and after giving effect to such distribution, our pro forma leverage ratio is less than 3.00 to 1.00 and before and after giving effect to such distribution the unused commitment amounts available under our senior secured revolving credit facility is at least 20% of the commitments in effect.    

 

Our senior secured revolving credit facility also requires us to maintain the following two financial ratios:

 

•a current ratio, tested quarterly, of our consolidated current assets to our consolidated current liabilities of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and

 

•a leverage ratio, tested quarterly, commencing with the fiscal quarter ended December 31, 2016, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated EBITDAX over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0.

The terms of the credit facility also restrict our ability to make distributions and investments.  As of March 31, 2017, the covenants of the Company’s senior secured revolving credit facility prohibit it from making any distributions.  At March 31, 2017, we were in compliance with the covenants. 

Cash flow used in operating activities 

Operating activities used cash of $4.1 million during the three months ended March 31, 2017 as compared to cash used by operating activities of $101.8 million during the comparable period in 2016, an increase of $97.7 million.  The increase in operating cash flows was attributable to various factors.  Cash-based items of net income (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 increase of approximately $9.9 million in the first three months of 2017.    Changes in restricted cash, 

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working capital and other assets and liabilities resulted in an increase of $87.8 million in the first three months of 2017 as compared to the corresponding period in 2016.

Cash flow used in investing activities 

Investing activities used cash for capital expenditures for property and equipment of $60.6 million during the three months ended March 31, 2017 as compared to $44.4 million during the comparable period of 2016.  

Cash flow provided by financing activities 

Financing activities provided cash of $62.9 million during the three months ended March 31, 2017 as compared to $141.1 million during the comparable period in 2016.  During the first three months of 2017, we drew down $55.1 million on our credit facility and we paid $0.1 million of deferred financing costs related to our credit facility and senior notes.  In addition, we received $7.9 million in capital contributions from our Class B limited partner.  In 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 and we paid $0.8 million of deferred financing costs related to our credit facility. 

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 2016 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, production, gathering and sale of oil, natural gas and natural gas liquids. These risks include, but are not limited to, commodity price volatility, low prices for oil, natural gas and/or natural gas liquids, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, uncertainties related to new technologies, geographical concentration of our operations, , environmental risks, weather risks, security 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, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties, and the other risks described under “Item 1A. Risk Factors” in our 2016 Annual Report and in this 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.    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  2016 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 2016 Annual Report. There have been no material changes to the disclosure regarding market risks other than as noted below. See Part I, Item 1, Notes  5 and 6 to our consolidated financial statements for a description of our outstanding derivative contracts at the most recent reporting date.

The fair value of our commodity derivative contracts at March 31, 2017 was a net asset of $7.3 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 $25.3 million (decrease in value) or $24.0 million (increase in value), respectively, as of March 31, 2017.  

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 $1.0 million, based on the balance outstanding as of March 31, 2017.

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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, 2017 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, 2017 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 2016 Annual Report.  There have been no material changes with respect to the risk factors disclosed in the 2016 Annual Report during the quarter ended March 31, 2017.  

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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